Index to Financial Statements

As filed with the Securities and Exchange Commission on June 25, 2012May 28, 2019

RegistrationRegistration No. 333-            333-227953

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 4

to

FormS-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Form S-1

 

 

LINN CO, LLCRoan Resources, Inc.

LINN ENERGY, LLC

(Exact Namename of Registrantregistrant as Specifiedspecified in its charter)

 

 

 

Delaware 1311 45-516662383-1984112
Delaware65-1177591

(State or other Jurisdictionjurisdiction of

Incorporationincorporation or Organization)organization)

 

(Primary Standard Industrial


Classification Code Number)

 

(IRS Employer


Identification Number)

600 Travis, Suite 510014701 Hertz Quail Springs Pkwy

Houston, Texas 77002Oklahoma City, OK 73134

(405)(281) 840-4000241-2150

(Address, including Zip Code,zip code, and Telephone Numbertelephone number, including Area Code,area code, of Registrant’s Principal Executive Offices)registrant’s principal executive offices)

 

 

David Edwards

Candice J. Wells

Charlene A. Ripley

600 Travis, Suite 5100

Chief Financial Officer

14701 Hertz Quail Springs Pkwy

Oklahoma City, OK 73134

(405)896-8050

Houston, Texas 77002

(281) 840-4000

600 Travis, Suite 5100

Houston, Texas 77002

(281) 840-4000

(Name, Address,address, including Zip Code,zip code, and Telephone Numbertelephone number, including Area Code,area code, of Agentagent for Service)service)

 

 

Copies to:

Alan Beck

Kelly Rose

James R. Brown

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

(713)758-2222

Baker Botts L.L.P.

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002-4995

(713) 229-1234

J. Michael Chambers

Brett E. Braden

Latham & Watkins LLP

811 Main Street

Suite 3700

Houston, Texas 77002

(713) 546-5400

 

 

Approximate date of commencement of proposed sale of the securities to the public:public: As soon as practicable after the effective date of this Registration Statement becomes effective.Statement.

If any of the securities being registered on this formForm are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨box:  ☒

If this formForm is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this formForm is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this formForm is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” andfiler,” “smaller reporting company” and “emerging growth company” inRule 12b-2 of the Exchange Act.Act:

Linn Co, LLC — Non-accelerated filer

Linn Energy, LLC —
Large accelerated filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

 

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of

Securities to be Registered

 

Proposed

Maximum Aggregate
Offering Price(1)(2)

 

Amount of

Registration Fee

Common shares

 $1,000,000,000 $114,600

Common units (3)

    

 

 

(1)Includes common shares issuable upon exercise of the underwriters’ option to purchase additional common shares.
(2)Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
(3)To be issued by Linn Energy, LLC. The common units are being registered solely due to the co-registrant status of Linn Energy, LLC, for which no separate registration fee is required.

The Registrantregistrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrantregistrant shall file a further amendment whichthat specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until thethis Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Index to Financial Statements

EXPLANATORY NOTE

This registration statement contains a prospectus to be used in connection with the offer and sale of common shares of Linn Co, LLC and the deemed offer and sale of Linn Energy, LLC units to be acquired by Linn Co, LLC with the proceeds from this offering pursuant to Rule 140 under the Securities Act of 1933.


Index to Financial Statements

The information in this prospectus is not complete and may be changed. These securitiesThe Selling stockholders may not be soldsell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdictionstate where suchthe offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED MAY 28, 2019

117,139,511 Shares

 

Subject to Completion, dated June 25, 2012LOGO

PROSPECTUSRoan Resources, Inc.

Class A Common stock

 

 

Linn Co, LLC

Common Shares

Representing Limited Liability Company Interests

This is the initial public offering of common shares (“shares”) representing limited liability company interests in Linn Co, LLC (“LinnCo”), a class of equity with indirect voting rights in LINN Energy, LLC (“LINN”). We are offering                 sharesThe selling stockholders named in this offering. We are a recently formed limited liability company that has elected to be treated as a corporation for U.S. federal income tax purposes.prospectus may offer 117,139,511 shares of our Class A common stock, par value $0.001 per share (“Class A common stock”), which the selling stockholders acquired in the reorganization described under “Reorganization.” The selling stockholders will receive all proceeds, and we will not receive any proceeds from the sale of the shares of Class A common stock being offered in this prospectus. We will usebear all costs, expenses, and fees in connection with the net proceeds from this offeringregistration of the shares of Class A common stock. The selling stockholders will bear all commissions and discounts, if any, attributable to acquire a number of units representing limited liability company interests (“units”) in LINN equal to the numbertheir sale of shares sold in this offering.of Class A common stock.

No public market currently exists for our shares. We intend to apply to list our sharesOur Class A common stock trades on the NASDAQ Global Select MarketNew York Stock Exchange (the “NYSE”) under the symbol “LNCO.”

We anticipate that the initial public offering price will be between $         and $         per share and will be determined based on, among other factors, the trading price of the LINN units, which are listed on the NASDAQ Global Select Market under the symbol “LINE.“ROAN.” The last reported salesales price of LINN unitsour Class A common stock on NASDAQMay 24, 2019 was $2.62 per share. You are urged to obtain current market quotations for our Class A common stock.

The selling stockholders may sell the shares of Class A common stock being offered by them from time to time on June 22, 2012 was $         per unit.the NYSE, in market transactions, in negotiated transactions or otherwise, and at prices and terms that will be determined by the then prevailing market price for the shares of Class A common stock or at negotiated prices directly or through a broker or brokers, who may act as agent or as principal or by a combination of such methods of sale. For additional information regarding the methods of sale, you should refer to the section entitled “Plan of Distribution” beginning on page 143 of this prospectus.

Because all of the shares of Class A common stock offered under this prospectus are being offered by the selling stockholders, we cannot currently determine the price or prices at which our shares may be sold under this prospectus.

We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this entire prospectus and any amendments carefully before you make your investment decision.

Investing in our sharesClass A common stock involves risks. Please readSeeRisk Factorsbeginning on page 29 of this prospectus.

These risks include the following:18.

 

Because our only assets will be LINN units, our cash flow and our ability to pay dividends on our shares are completely dependent upon the ability of LINN to make distributions to its unitholders.

 

We will incur corporate income tax liabilities on income allocated to us by LINN with respect to LINN units we own, which may be substantial.

An active trading market for our shares may not develop, and even if such a market does develop, the market price of our shares may be less than the price you paid for your shares and less than the market price of the LINN units.

Our shareholders will only be able to indirectly vote on matters on which LINN unitholders are entitled to vote, and our shareholders are not entitled to vote to elect our directors. Therefore, you will only be able to indirectly influence the management and board of directors of LINN, and you will not be able to directly influence or change our management or board of directors.

Your shares are subject to certain call rights that could require you to involuntarily sell your shares at a time or price that may be undesirable.

Our limited liability company agreement limits the fiduciary duties owed by our officers and directors to our shareholders, and LINN’s limited liability company agreement limits the fiduciary duties owed by LINN’s directors to its unitholders, including us.

Per ShareTotal

Price to the public

$            $            

Underwriting discounts and commissions

$$

Proceeds to us

$$

We have granted the underwriters an option for a period of 30 days to purchase up to an additional                 shares on the same terms and conditions set forth above.

Affiliates of certain of the underwriters in this offering are lenders under LINN’s revolving credit facility and, accordingly, if LINN elects to use the proceeds it receives from LinnCo to repay debt outstanding under that facility, those lenders would indirectly receive a portion of the net proceeds from this offering. Please read “Underwriting—Conflicts of Interest.”

Neither the Securities and Exchange Commission nor any other regulatory bodystate securities commission has approved or disapproved of these securities or passed on the adequacydetermined if this prospectus is truthful or accuracy of this prospectus.complete. Any representation to the contrary is a criminal offense.

Barclays, on behalf

The date of the underwriters, expects to deliver the shares on or aboutthis prospectus is                 , 2012.2019.

Barclays

Prospectus dated                     , 2012


Index to Financial Statements

TABLE OF CONTENTS

 

PROSPECTUS SUMMARYPROSPECTUS SUMMARY

   1 

OverviewRISK FACTORS

   118 

LinnCoCAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

1

LINN

3

Business Strategy

5

Competitive Strengths

6

Recent Developments

7

Questions and Answers about LinnCo

8

Risk Factors

10

Management of LinnCo

11

Comparison of LINN Units with LinnCo Shares

11

Ownership of LINN

15

Principal Executive Offices and Internet Address

15

The Offering

16

Summary Historical and Pro Forma Financial and Operating Data of LINN

21

Summary Reserve and Operating Data

24

RISK FACTORS

29

Risks Related to LINN’s Business

29

Risks Inherent in an Investment in LinnCo

37

Tax Risks to Shareholders

42

USE OF PROCEEDS

   45 

CAPITALIZATION USEOF LINNCO PROCEEDS

46

CAPITALIZATION OF LINN

   47 

OUR DIVIDEND POLICYDIVIDEND POLICY

   48 

Our Dividend PolicySELECTED HISTORICALAND UNAUDITED PRO FORMA FINANCIAL DATA

48

LINN’s Distribution Policy

48

LINN’s Historical Distributions

   49 

SELECTED HISTORICAL FINANCIAL MANAGEMENTS DISCUSSIONAND OPERATING DATA ANALYSISOF LINN FINANCIAL CONDITIONAND RESULTSOF OPERATIONS

   5051 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSBUSINESS

   5379 

LinnCoMANAGEMENT

   53105 

LINNEXECUTIVE COMPENSATION

54

BUSINESS

92

LinnCo

92

LINN

92

MANAGEMENT

104

Our Board of Directors

106

Executive Compensation

107

Director Compensation

107

Security Ownership of Certain Beneficial Owners and Management

107

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

109

Our Relationship with Linn Energy, LLC

109

Indemnification of Officers and Directors

109

DESCRIPTION OF OUR SHARES

110

Voting Rights

110

Dividends

110

Issuance of Additional Shares

110

Maintenance of Ratio of Shares to Units

110

Transfer Agent and Registrar

111

Transfer of Shares

111

i


Index to Financial Statements

DESCRIPTION OF THE LINN UNITS

   112 

LINN’s Cash Distribution PolicyPRINCIPALAND SELLING STOCKHOLDERS

   112124 

This prospectus is part of a shelf registration statement that we have filed with the SEC using a “shelf” registration process. Under this shelf registration process, the selling stockholders may, from time to time, offer and sell the shares described in this prospectus in one or more offerings.

This prospectus provides you with a general description of the shares the selling stockholders may offer. Each time the selling stockholders sell our shares using this prospectus, to the extent necessary, we may provide a prospectus supplement that will contain specific information about the terms of that offering, including the number of shares being offered, the manner of distribution, the identity of any underwriters or other counterparties and other specific terms related to the offering. The prospectus supplement may also add, update or change information contained in this prospectus. To the extent that any statement made in an accompanying prospectus supplement is inconsistent with statements made in this prospectus, the statements made in this prospectus will be deemed modified or superseded by those made in the accompanying prospectus supplement. You should read both this prospectus and any prospectus supplement together.

You should rely only on the information contained in this prospectus. Weprospectus, as may be amended and supplemented from time to time, and any free writing prospectus prepared by us or on behalf of us or the information to which we have not, andreferred you. Neither we nor the underwritersselling stockholders have not, authorized anyone to provide you with information different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assumefrom that the information appearingcontained in this prospectus, is accurate as may be amended and supplemented from time to time, and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, the date on the front coverany other information that others may give you. The selling stockholders are offering to sell shares of this prospectus. Our business, financial condition, resultsClass A common stock and seeking offers to buy shares of operationsClass A common stock only in jurisdictions where offers and prospects may have changed sincesales are permitted.

This prospectus contains forward-looking statements that date.are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

i


Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications orand other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we, nor the selling stockholders have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

Basis of Presentation

Unless otherwise indicated or the context otherwise requires, references herein to

“Roan,” “we,” “our,” “us,” the “Company” and “our company” refer (i) prior to the consummation of our reorganization described under “Reorganization,” to Roan LLC and (ii) after the consummation of such reorganization, to Roan Inc. and its consolidated subsidiaries;

“Roan Inc.” refer to Roan Resources, Inc.;

“Roan LLC” refer to Roan Resources LLC, our predecessor;

“Reorganization” refer to the transactions contemplated by the Merger Agreements and the Master Reorganization Agreement, as described in “Reorganization”;

“Old Linn” refer to Linn Energy, Inc. prior to the Riviera Separation and described in “Reorganization”;

“New Linn” refer to New LINN Inc. (subsequently renamed Linn Energy, Inc.);

“Roan Holdings” refer to Roan Holdings, LLC;

“Roan Holdco” refer to Roan Holdings Holdco, LLC, a wholly owned subsidiary of Roan Holdings;

“Riviera” refer to Riviera Resources, Inc.;

“Riviera Separation” refer to the reorganization transactions pursuant to which Old Linn contributed certain of its assets to Riviera except for its 50% equity interest in Roan LLC, as further described in “Reorganization”;

“Legacy Linn Stockholders” refer to the stockholders of New Linn;

“Effective Date” refer to September 24, 2018, the closing date of the Reorganization;

 

ii


Index
the play located in the Canadian, Grady and McClain counties in the Anadarko Basin of Oklahoma;

“SCOOP” refer to the South Central Oklahoma Oil Province play principally located in the Anadarko Basin area of Oklahoma; and

“STACK” refer to the “Sooner Trend, Anadarko (Basin), Canadian and Kingfisher” play located in the Anadarko Basin area of Oklahoma.

Roan Inc. was incorporated in September 2018 to serve as a holding company and, prior to our reorganization, had no previous operations, assets or liabilities. Unless otherwise indicated, the historical financial, reserve and operational information presented in this prospectus (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is that of Roan LLC, our predecessor. The historical financial and operational information of Roan LLC presented in this prospectus, (i) prior to August 31, 2017, the date of the completion of the Contribution (as defined herein) described under “Recent Developments—History and Reorganization” and “Reorganization,” is that of Citizen Energy II, LLC (“Citizen”), the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the historical financial and operating information of Citizen prior to August 31, 2017 does not include financial information relating to certain oil and gas assets contributed to Roan LLC by subsidiaries of Linn Energy, Inc. (the “Linn Contributed Business”).

The financial data and certain other data presented in this prospectus have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this prospectus. In addition, certain percentages presented in this prospectus reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers or may not sum due to rounding.

iii


PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information you should consider before buying shares in this offering. Therefore, youYou should read thisthe entire prospectus carefully, including the risks discussed ininformation under the section titledheadings “Risk Factors” beginning on page 29Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements of Linn Energy, LLC (“LINN”) and the notes to those financial statements includedappearing elsewhere in this prospectus. This prospectus also contains importantYou should read “Risk Factors” for more information about LINN, including information about its businesses and financial and operating data, all of whichimportant risks that you should readconsider carefully before buying sharesinvesting in our Class A common stock. Certain oil and gas industry terms used in this offering.prospectus are defined in the “Glossary of Oil and Natural Gas Terms” in Annex A of this prospectus.

Roan Inc. was incorporated in September 2018 to serve as a holding company and, prior to our reorganization, had no previous operations, assets or liabilities. Unless otherwise indicated, otherwise, the historical financial, reserve and operational information presented in this prospectus assumes (1) an initial public offering price(i) on and after September 24, 2018, is that of $                 per share (the midpointRoan Inc., and (ii) prior to September 24, 2018, is that of the range set forth on the cover pageRoan LLC, our predecessor. The historical financial and operational information of this prospectus) and (2) that the underwriters do not exercise their option to purchase additional shares. We include a glossary of some of the terms usedRoan LLC presented in this prospectus, as Appendix A.(i) prior to August 31, 2017, the date of the completion of the Contribution described under “Recent Developments—History and Reorganization” and “Reorganization,” is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the historical financial and operating information of Citizen prior to August 31, 2017 does not include financial information relating to the Linn Contributed Business.

DeGolyer and MacNaughton,Our Company

We are an independent petroleum engineers, provided the estimates of LINN’s proved oil and natural gas reserves ascompany focused on the development of December 31, 2009, 2010our assets throughout the eastern and 2011 as well as estimates of proved reserves associated with the Hugoton Acquisition, the East Texas Acquisition and thesouthern Anadarko Joint Venture (each as defined below). All other reserve information included herein is based on internal estimates. As used herein, “Pro Forma Proved Reserves” represent the sum of (i) LINN’s estimated proved reserves as of December 31, 2011 and (ii) the estimated proved reserves acquired in the 2012 Acquisitions (as defined below). For information regarding the dates and commodity prices atBasin. The Anadarko Basin, which reserve information for the 2012 Acquisitions was calculated, see the table on page 4. As used in this prospectus, the term “LinnCo” and the terms “we,” “our,” “us” and similar terms refer to Linn Co, LLC, unless the context otherwise requires. In addition, the term “LINN” refers to Linn Energy, LLC. As used in this prospectus, the term “shares” refers to common shares representing limited liability company interests in LinnCo and “units” refers to units representing limited liability company interests in LINN.

Overview

LinnCo

We are a recently formed Delaware limited liability company that has elected to be treated as a corporation for United States (“U.S.”) federal income tax purposes. Our sole purpose is to own LINN units and we expect to have no assets or operations other than those related to our interest in LINN. As a result, our financial condition and results of operations will depend entirely upon the performance of LINN. We will use the net proceedsspans from this offering to acquire a number of LINN units equalsouth-central Oklahoma to the number of LinnCo shares sold in this offering.

At the closing of this offering, we will own one LINN unit for each of our outstanding shares, and our limited liability company agreement requires that we maintain a one-to-one ratio between the number of our shares outstanding and the number of LINN units we own. When LINN makes distributions on the units, we will pay a dividend on our sharesnortheast corner of the cash we receive in respect of our LINN units, net of reserves for income taxes payable by us. For the periods ending December 31, 2012, 2013, 2014 and 2015, we estimate that our income tax liability will not exceed     % of the cash distributed to us. On April 24, 2012, LINN declared a regular quarterly cash distribution of $0.725 per unit, or $2.90 per unit on an annualized basis. Accordingly, if LINN were to maintain its current annualized distribution of $2.90 per unit through 2015, the amount reserved to pay income taxes of LinnCo is estimated to be no more than $         per share for the periods ending December 31, 2012, 2013, 2014 and 2015.

Like shareholders of a corporation, our shareholders will receive a Form 1099-DIV and will be subject to U.S. federal income tax, as well as any applicable state or local income tax, on taxable dividends received by them. We estimate that if you own the shares that you purchase in this offering through December 31, 2015, you will recognize, on a cumulative basis, an amount of taxable dividend income that will be     % or less of the cash

Index to Financial Statements

dividends paid to you during that period. The excess of the cash dividends that you receive over your taxable dividend income during that period will reduce your tax basis in your shares. Our shareholders will not report our items of income, gain, loss and deduction, nor will they receive a Schedule K-1. Our shareholders also will not be subject to state income tax filings in the various states in which LINN conducts operations as a result of owning our shares. Please read “Material U.S. Federal Income Tax Consequences” for additional details.

We will submit to a vote of our shareholders any matter submitted by LINN to a vote of its unitholders, including any election of LINN’s directors. We will vote LINN units that we hold in the same manner as the owners of our shares vote (or refrain from voting) their shares on those matters. In addition, our shareholders will be entitled to vote on certain fundamental matters affecting LinnCo. Our shareholders will not be entitled to vote to elect our board of directors. The sole voting share that is entitled to vote to elect our board of directors is owned by LINN through one of its wholly-owned subsidiaries. Our initial board of directors will be identical to LINN’s board of directors, and our initial officers will be the individuals who serve as officers of LINN. Please see “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement” for a detailed description of these matters.

Index to Financial Statements

LINN

LINNTexas panhandle, is one of the largest publicly traded, U.S.-focused, independentand most prolific onshore oil and natural gas companiesbasins in the United States, featuring multiple producing horizons and extensive well production history demonstrated over seven decades of development. We focus our development on formations where we believe we can apply our technical and operational expertise in order to increase production and cash flow. Our objective is to maximize shareholder value and corporate returns by generating steady production growth, strongpre-tax margins and significant cash flow.

Through December 31, 2018, we and our predecessors have drilled 214 gross (72 net) wells in the largest publicly traded upstreamMerge, SCOOP and STACK plays. Our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs, and provides us development opportunities through multiple stacked prospective development horizons. We believe these development horizons have been substantiallyde-risked through the development of more than 400 horizontal wells since early 2014, of which 152 were drilled by us or our predecessors, and over 4,450 vertical wells drilled in our development area, as well as associated subsurface data, including well cores and logs and3-D seismic and the consistent geology surrounding our position. As of December 31, 2018, we operated 163 gross (131 net) horizontal producing wells and had an interest in an additional 317 gross (19 net) horizontal producing wells.

As of December 31, 2018, we held leasehold interests in approximately 383,000 gross (172,000 net) acres in the Anadarko Basin. As of December 31, 2018, our total estimated proved reserves were approximately 305,959 MBoe. For the quarter ended March 31, 2019 our average net daily production was 48.9 MBoe/d (approximately 26% oil, 44% natural gas company that is treated as a partnership for U.S. federal income tax purposes. LINN is focusedand 30% NGLs).



We have chosen to focus our development efforts on the development and acquisition of long-life oil and natural gas properties, which complement its asset profile in various producing basins withinMerge play, as we believe it benefits from the U.S. LINN’s properties are located in eight operating regions in the U.S.:following attributes:

 

Mid-Continent, which includes propertiesStacked Formations. The Merge has been proven to be prospective for two primary resource formations: the Mayes (Meramec/Sycamore equivalent) formation and the Woodford formation. We and our predecessors have demonstrated successful economic development of both benches, with 63 gross (53 net) and 80 gross (65 net) horizontal operated wells producing from the Mayes and Woodford formations, respectively, as of December 31, 2018.

Reservoir Quality. Reservoir characteristics from petrophysical analysis demonstrate high porosity and permeability development in Oklahoma, Louisiana andthe Merge as compared to other unconventional plays.

Phase Window Positioning. The thermal maturity of the source rock throughout the eastern portion of the Texas Panhandle (includingMerge results in production profiles characterized by high percentages of oil and NGLs. Specifically, over 80% of our operated acreage is within areas we believe demonstrate higher percentage production of oil and NGLs within the Granite Wash and Cleveland horizontal plays);Merge play.

 

Hugoton Basin,Pressure Gradients. Geopressure across our operated acreage position in the Merge play ranges from slightly to significantly overpressured at approximately 0.45 to 0.65 pounds per square inch (“psi”) per foot of true vertical depth, resulting in superior well deliverability and improved GOR trend stability as compared to normal to under-pressured reservoirs.

As of December 31, 2018, we had assembled a total leasehold position of approximately 172,000 net acres, which includes properties located primarilyis predominantly concentrated in Kansasthe Merge and SCOOP plays. In addition to the Shallow Texas Panhandle;subsurface benefits of our position, we believe our acreage position benefits from the following characteristics:

High Degree of Operational Control. We expect that we will be able to control operations on approximately 71% of our acreage in the Merge, SCOOP and STACK plays. For these purposes, we have assumed that we will control any unit in which we have leased a minimum of 37.5% of the acreage in the unit. Operational control of our leasehold positions allows us to control the development and production methods, as well as the pace of development on our wells.

 

Green River Basin, which includes properties located in southwest Wyoming;

Permian Basin, which includes areas in west Texas and southeast New Mexico;

Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;

California, which includes the Brea Olinda Field of the Los Angeles Basin;

Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming; and

East Texas, which includes properties located in east Texas.

LINN’s total proved reserves at December 31, 2011 were 3.4 Tcfe, of which approximately 34% were oil, 50% were natural gas and 16% were NGL. Approximately 60% of LINN’s total proved reserves were classified as proved developed, with a total standardized measure of discounted future net cash flows of $6.6 billion. At December 31, 2011, LINN operated 7,759, or 69%, of its 11,230 gross productive wells and had an average proved reserve-life index of approximately 22 years, based on LINN’s total proved reserves at December 31, 2011 and annualized production for the three months ended December 31, 2011.

On June 21, 2012, LINN entered into a purchase agreement for certain oil and natural gas properties located in the Green River Basin area of southwest Wyoming for a contract price of approximately $1.025 billion (the “Jonah Acquisition”). LINN anticipates the Jonah Acquisition will close on or before July 31, 2012, and will be financed with the proceeds from borrowings under its revolving credit facility. In addition to customary closing conditions, the Jonah Acquisition is subject to a preferential right of purchase that encompasses substantially all of the properties. The expiry period for waiver or acceptance of the preferential right of purchase is anticipated during the first week of July 2012. The Jonah Acquisition includes approximately 753 Bcfe of estimated proved reserves. The estimated proved reserves for the Jonah Acquisition were based on LINN’s preliminary internal evaluation of information provided by the seller.

On May 1, 2012, LINN completed the acquisition of certain oil and natural gas properties located in east Texas (the “East Texas Acquisition”) for total consideration of approximately $168 million. On March 30, 2012, LINN completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin area of southwestern Kansas (the “Hugoton Acquisition”) for total consideration of approximately $1.17 billion. On April 3, 2012, LINN entered into a joint venture agreement (the “Anadarko Joint Venture”) with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby LINN will participate as a partner in the CO2-enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming. As part of this joint venture, Anadarko assigned LINN 23% of its interest in the field in exchange for future funding by LINN of $400 million of Anadarko’s development costs. See “—Recent Developments.” Giving effect to the East Texas

Index to Financial Statements

Acquisition, the Hugoton Acquisition, the Anadarko Joint Venture and the Jonah Acquisition, LINN’s pro forma proved reserves are approximately 5.1 Tcfe, of which approximately 25% are oil, 55% are natural gas and 20% are NGL, with approximately 66% proved developed.

LINN generated adjusted EBITDA of approximately $998 million for the year ended December 31, 2011 and $302 million for the three months ended March 31, 2012. See “—Non-GAAP Financial Measures” for a reconciliation of adjusted EBITDA to net income (loss). For 2012, LINN estimates its total capital expenditures, excluding acquisitions, will be approximately $1.0 billion, including $940 million related to its oil and natural gas capital program and $40 million related to its plant and pipeline capital program. This estimate is under continuous review and is subject to ongoing adjustments. LINN expects to fund these capital expenditures primarily with cash flow from operations and borrowings under LINN’s revolving credit facility.

The following table sets forth certain information with respect to LINN’s Pro Forma Proved Reserves at December 31, 2011 and average daily production for the three months ended March 31, 2012:

Region

  Pro Forma Proved
Reserves (Bcfe)(1)
   % Oil and NGL  % Proved
Developed
  Average Daily
Production For The
Three Months Ended
March 31, 2012
(MMcfe/d)
 

Mid-Continent

   1,884     41  53  273  

Hugoton Basin(2)

   1,081     47  87  39  

Green River Basin(3)

   753     27  56    

Permian Basin

   527     79  56  89  

Michigan/Illinois

   317     4  91  36  

California

   193     93  93  13  

Williston/Powder River Basin(2)

   189     92  63  21  

East Texas(4)

   110     3  100    
  

 

 

   

 

 

  

 

 

  

 

 

 

Total

   5,054     45  66  471  
  

 

 

   

 

 

  

 

 

  

 

 

 

(1)Except as otherwise noted, proved reserves for oil and natural gas assets were calculated on December 31, 2011, the reserve report date, and use a price of $4.12/MMBtu for natural gas and $95.84/Bbl for oil, which represent the unweighted average of the first-day-of-the-month prices for each of the twelve months immediately preceding December 31, 2011.
(2)Pro forma proved reserves for the Hugoton Acquisition (in the Hugoton Basin region) and the Anadarko Joint Venture (in the Williston/Powder River Basin region) were calculated using a price of $3.73/MMBtu for natural gas and $98.02/Bbl for oil, which represent the unweighted average of the first-day-of-the-month prices for each of the twelve months ending March 1, 2012, the most recent twelve-month period prior to the closing of each of those transactions. The proved reserves for the Anadarko Joint Venture were based on LINN’s preliminary internal evaluation.
(3)Pro forma proved reserves for the Jonah Acquisition (in the Green River Basin region) were calculated using a price of $3.15/MMBtu for natural gas and $95.63/Bbl for oil, which represents the unweighted average of the first-day-of-the-month prices for each of the twelve months ending June 1, 2012, the most recent twelve-month period prior to the signing of the Jonah Acquisition. The estimated proved reserves for the Jonah Acquisition were based on LINN’s preliminary internal evaluation of information provided by the seller.
(4)Pro forma proved reserves for the East Texas Acquisition were calculated using a price of $3.54/MMBtu for natural gas and $97.65/Bbl for oil, which represent the unweighted average of the first-day-of-the-month prices for each of the twelve months ending April 1, 2012, the most recent twelve-month period prior to the closing of the East Texas Acquisition.

Index to Financial Statements

LINN was formed as a Delaware limited liability company in March 2003 by Michael C. Linn, Quantum Energy Partners and non-affiliated equity investors with an aggregate equity investment of $16 million. In January 2006, LINN completed its $261 million initial public offering. Since its initial public offering, LINN has successfully executed on its strategy, and substantially grown its asset base and distributions on its units. LINN has increased its quarterly cash distribution by approximately 81% from $0.40 per unit, or $1.60 per unit on an annualized basis, at the time of its initial public offering, to $0.725 per unit, or $2.90 per unit on an annualized basis. At the time of its initial public offering, LINN’s assets consisted primarily of oil and natural gas properties in the Appalachian Basin, mainly in Pennsylvania, West Virginia, New York and Virginia (subsequently sold in 2008) with proved reserves of approximately 190 Bcfe as of September 30, 2005 and average daily production of approximately 13 MMcfe/d for the three months ended September 30, 2005. Since then, LINN has successfully grown and diversified its asset base to include properties across eight operating regions with total Pro Forma Proved Reserves of approximately 5.1 Tcfe and average daily production for the three months ended March 31, 2012 of approximately 471 MMcfe/d.

Business StrategyContiguous Acreage Position.

LINN’s primary goal is to provide stability and growth of distributions for the long-term benefit of its unitholders. The following is a summary of the key elements of LINN’s business strategy:

Grow through acquisition of long-life, high quality properties;

Efficiently operate and develop acquired properties; and

Reduce cash flow volatility through hedging.

LINN’s business strategy is discussed in more detail below.

Grow Through Acquisition of Long-Life, High Quality Properties. LINN’s acquisition program targets oil and natural gas properties that it believes will be financially accretive and offer stable, long-life, and high quality production with relatively predictable decline curves, as well as lower-risk development opportunities. LINN evaluates acquisitions based on decline profile, reserve life, operational efficiency, field cash flow, development costs and rate of return. As part of this strategy, LINN continually seeks to optimize its asset portfolio, which may include the divestiture of non-core assets. This allows LINN to redeploy capital into projects to develop lower-risk, long-life and low-decline properties that are better suited to its business strategy.

Since January 1, 2007, LINN has completed 38 acquisitions of oil and natural gas properties and related gathering and pipeline assets, acquiring proved reserves totaling approximately 3.7 Tcfe at the date of acquisition, at an average aggregate cost of approximately $2.19 per Mcfe.

LINN continually evaluates potential acquisition opportunities that would further its strategic objectives and engages from time to time in discussions with potential sellers. Assets acquired in one or more of such transactions may have a material effect on LINN’s business, financial condition and results of operations.

Efficiently Operate and Develop Acquired Properties. LINN has centralized the operation of its acquired properties into defined operating regions to minimize operating costs and maximize production and capital efficiency. LINN maintains a large inventory of drilling and optimization projects within each operating region to achieve organic growth from its capital development program. LINN generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects that not only replace production, but add value through reserve and production growth and future operational synergies. LINN’s development program is focused on lower-risk, repeatable drilling opportunities to maintain and/or grow cash flow. Many of the wells

Index to Financial Statements

are completed in multiple producing zones with commingled production and long economic lives. In addition, LINN’s experienced workforce and scalable infrastructure facilitate the efficient development of its properties.

Reduce Cash Flow Volatility Through Hedging. LINN seeks to hedge a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to pay distributions, service debt and manage its business. By removing a significantA substantial portion of the price volatility associated with future production, LINN expectssections in which we have operational control are offset to mitigate, but not eliminate, the potential effectsnorth or south by adjacent controlled sections. Specifically, approximately 66% of variability in cash flow from operations due to fluctuations in commodity prices.

These commodity hedging transactions are primarilyour sections in the formMerge, SCOOP and STACK plays can be developed on a multi-unit basis. As a result, we are able to develop long lateral horizontal wells for the majority of swap contracts and put options that are designed to provide a fixed price (swap contracts) or fixed price floor with the opportunity for upside (put options) that LINN will receiveour drilling program, which we believe have exhibited superior economics as compared to floating market prices. As of May 31, 2012, LINN had derivative contracts in place for 2012 through 2017 at average prices ranging from a low of $91.04 per Bbl to a high of $98.56 per Bbl for oil and from a low of $4.53 per MMBtu to a high of $5.43 per MMBtu for natural gas. Additionally, LINN has derivative contracts in place covering a substantial portion of its natural gas basis exposure to Panhandle, MichCon and Permian differentials through 2015 and Houston Ship Channel differentials through 2016 and its timing risk exposure on Mid-Continent, Hugoton Basin and Permian Basin oil sales through 2017. LINN also intends to enter into additional derivatives contracts in connection with the Jonah Acquisition.

In addition, LINN may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. Currently, LINN has no outstanding interest rate swaps.

Competitive Strengths

LINN believes the following strengths provide significant competitive advantages:

Large and High Quality Asset Base with a Long Reserve Life. LINN’s reserve base is characterized by lower geologic risk and well-established production histories and exhibits low production decline rates. Based on LINN’s total proved reserves at December 31, 2011, and annualized production for the three months ended December 31, 2011, LINN had an average reserve-life index of approximately 22 years. LINN’s Pro Forma Proved Reserves are also diversified by product with approximately 25% oil, 55% natural gas and 20% natural gas liquids (“NGL”), with approximately 66% classified as proved developed.

Significant Inventory of Lower-Risk Development Opportunities. LINN has a significant inventory of projects in its core areas that it believes will support its development activity. At December 31, 2011, LINN had approximately 6,450 identified drilling locations, of which approximately 2,300 were proved undeveloped drilling locations and the remainder were unproved drilling locations. During the year ended December 31, 2011, LINN drilled a total of 294 gross wells with an approximate 99% success rate.

Significant Scale of Operations. As of June 1, 2012, LINN had interests in approximately 15,000 gross productive wells (approximately 71% operated) and approximately 1.8 million net acres across seven regions in the U.S. The Mid-Continent, Hugoton Basin and Permian Basin regions account for approximately 69% of LINN’s Pro Forma Proved Reserves. The scale of operations allows LINN to benefit from economies of scale in both drilling and production operations and capitalize on acquired technical knowledge to lower production costs and maintain a high success rate on its drilling program. Furthermore, LINN owns integrated gathering and transportation infrastructure in the Mid-Continent and Hugoton Basin regions, which improves LINN’s cost structure.

Multi-Year Organic Growth Opportunities. In addition to growth through acquisitions, LINN’s asset base provides significant opportunities to grow production organically. Key drivers of LINN’s organic growth potential include its properties in the Granite Wash play in the Mid-Continent region and the Wolfberry trend in

Index to Financial Statements

the Permian Basin region. LINN has approximately 95,000 net acres in the Granite Wash play, which covers a trend extending from the Texas Panhandle eastward into southwestern Oklahoma. The Granite Wash play is characterized by liquids-rich multi-layer reservoirs which provide for attractive horizontal development opportunities. Since the inception of LINN’s horizontal drilling program in the Granite Wash in 2009, LINN has increased production to approximately 137 MMcfe/d (43% liquids). As of March 31, 2012, LINN had identified more than 600 horizontal drilling locations in the Granite Wash and multiple vertical infill drilling locations, representing a 10-plus year drilling inventory. LINN is also evaluating several oil-bearing intervals in the Texas Panhandle including the Hogshooter, Lansing, Cleveland and Tonkawa formations. As a result of technical mapping, LINN has already identified approximately 50 additional well locations in the Hogshooter interval. In the Permian Basin region, LINN owns 31,000 net acres in the Wolfberry trend (targeting the liquids-rich Spraberry and Wolfcamp zones). The Wolfberry trend offers significant growth potential driven primarily by infill drilling and downspacing. Since entering the Permian Basin in the fall of 2009, LINN has increased production to approximately 14,800 Boepd as of the first quarter of 2012 through a combination of organic development and acquisitions. LINN estimates that it has a four-year drilling inventory with approximately 400 future drilling locations in the Wolfberry trend.

High Percentage of Production Hedged. Currently, LINN hedges its production with swap contracts and put options to minimize its cash flow volatility while maintaining optionality for future upward movement in commodity prices. Swap contracts provide a fixed price and put options provide a fixed price floor with opportunity for upside that LINN will receive as compared to floating market prices. Based on current production estimates, LINN is approximately 100% hedged on expected natural gas production through 2017 and 100% hedged on expected oil production through 2016. LINN also intends to enter into additional derivatives contracts in connection with the Jonah Acquisition.

High Percentage of Operated Properties. For the year ended December 31, 2011, approximately 82% of LINN’s production came from wells over which it had operating control. Maintaining control of its properties allows LINN to use its technical and operational expertise to manage overhead, production, drilling costs and capital expenditures and to control the timing of development activities.

Competitive Cost of Capital and Financial Flexibility. Unlike many master limited partnerships, LINN does not have any incentive distribution rights, or IDRs, that entitle the IDR holders to increasing percentages of cash distributions as unit distributions grow. LINN believes that its lack of IDRs provides it with a lower cost of equity, thereby enhancing its ability to compete for future acquisitions.

Additionally, LINN has regularly and successfully raised significant capital throughout different financial cycles. Since LINN’s initial public offering in January 2006, it has raised approximately $5.2 billion in follow-on equity offerings and approximately $5.4 billion in debt offerings. Furthermore, as of March 31, 2012, LINN’s revolving credit facility had a $2.6 billion borrowing base, subject to a maximum commitment of $2 billion. LINN believes this financial flexibility and access to the capital markets provides LINN with a substantial competitive advantage in consummating acquisitions.

Recent Developments

Acquisitions

Jonah Acquisition. On June 21, 2012, LINN entered into a purchase agreement in connection with the Jonah Acquisition for a contract price of approximately $1.025 billion. LINN anticipates the Jonah Acquisition will close on or before July 31, 2012, and will be financed with the proceeds from borrowings under its revolving credit facility. In addition to customary closing conditions, the Jonah Acquisition is subject to a preferential right of purchase that encompasses substantially all of the properties. The expiry period for waiver or acceptance of

Index to Financial Statements

the preferential right of purchase is anticipated during the first week of July 2012. The Jonah Acquisition includes approximately 753 Bcfe of estimated proved reserves. The estimated proved reserves for the Jonah Acquisition were based on LINN’s preliminary internal evaluation of information provided by the seller.

East Texas Acquisition. On May 1, 2012, LINN completed the East Texas Acquisition for total consideration of approximately $168 million. The properties acquired in east Texas include (1) proved reserves of approximately 110 Bcfe, all of which are proved developed producing; (2) approximately 430 producing wells on approximately 19,800 contiguous acres; and (3) average daily production of approximately 24 MMcfe/d (97% natural gas).

Hugoton Acquisition. On March 30, 2012, LINN completed the Hugoton Acquisition for total consideration of approximately $1.17 billion. The properties acquired in the Hugoton Acquisition included: (1) proved reserves of approximately 701 Bcfe, of which 100% is proved developed; (2) approximately 2,400 producing wells with average daily production of approximately 110 MMcfe/d, of which approximately 63% is natural gas and 37% is NGL; (3) more than 800 future drilling locations, including over 400 proved locations; and (4) the JayHawk Natural Gas Processing Plant, which processes substantially all of the production from the acquired properties, with 450 MMcf/d of processing capacity.

Joint Venture

Anadarko Joint Venture. On April 3, 2012, LINN entered into the Anadarko Joint Venture, whereby LINN will participate as a partner in the CO2-enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming. Anadarko assigned LINN 23% of its interest in the field in exchange for future funding by LINN of $400 million of Anadarko’s development costs. LINN expects to invest a total of $600 million in the joint venture over the next three to six years, which includes the $400 million of Anadarko’s costs and $200 million net to LINN’s assigned interest. Anadarko has been utilizing CO2 to develop this field since 2004. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the agreement date.

The acquisitions and joint venture described above are referred to in this prospectus as the “2012 Acquisitions.”

Questions and Answers About LinnCo

Why is LinnCo being created?

LinnCo is being created to enhance LINN’s ability to raise additional equity capital to execute on its acquisition and growth strategy. As LINN continues to grow, the size of individual acquisitions it pursues and its related financing needs are expected to increase. LINN believes that the LinnCo structure will allow LINN to expand its investor base through offerings of LinnCo shares, the proceeds of which will go to LINN for use in executing its strategy, in return for a number of LINN units equal to the number of LinnCo shares sold.

Why does LINN believe that LinnCo will enhance LINN’s ability to raise equity?

LinnCo will be taxed as a corporation, which will enable holders of LinnCo shares to invest indirectly in LINN without the associated tax-related obligations of owning a LINN unit. For example, holders of LinnCo shares will receive a Form 1099-DIV rather than a Schedule K-1, will generally not have unrelated business taxable income, or UBTI, and will not be required to file state income tax returnsshorter laterals as a result of owning LinnCo shares. LINN believes that this structure will appeal to investors that would like to invest in a dividend-paying oil and natural gas exploration and production company, but currently do not invest in LINN units because of UBTI consequences and more onerous tax reporting requirements.

Index to Financial Statements

Why doesn’t LINN just increase the size of its LINN unit offerings?

While LINN has been one of the most active energy-focused master limited partnership equity issuers in recent years, we believe that expanding the investor base to include institutions, individual retirement accounts, foreign investors and tax-exempt investors will provide LINN with equity-raising opportunities significantly beyond its current capacity.

How will LinnCo quarterly dividends be determined?

LinnCo will own a number of LINN units equal to the number of LinnCo shares outstanding and will receive the same distribution per LINN unit as all other LINN unitholders. When LinnCo receives a quarterly distribution from LINN, it will reserve an amount equal to LinnCo’s estimated income tax liability, and will distribute the balance as a dividend to LinnCo shareholders. We currently estimate that for the periods ending December 31, 2012, 2013, 2014 and 2015, LinnCo’s income tax liability will not exceed         % of the cash LINN distributes to us. Accordingly, if LINN were to maintain its current annualized distribution of $2.90 per unit through 2015, the annual LinnCo dividend would not be less than $             per share.

What rights will LinnCo shareholders have with respect to the governance of LINN and LinnCo?

LinnCo will submit to a vote of its shareholders any matter submitted by LINN to a vote of its unitholders, which will include the annual election of the LINN board of directors. LinnCo will vote the LINN units it holds in the same manner as our shareholders vote on those matters. Our shareholders will also be entitled to vote on certain fundamental matters affecting LinnCo, but will not have the right to elect the LinnCo board of directors. LINN holds the sole voting share in LinnCo, and therefore will elect the LinnCo board. LinnCo’s initial board of directors will be composed of the same members as LINN’s board of directors.

Will there be future offerings of LinnCo shares?

As LINN continues to execute on its acquisition and growth strategy, it expects to continue to require additional equity capital. LinnCo may make future sales of LinnCo shares to facilitate this strategy, and such future sales may be made separately or in tandem with future sales of LINN units depending on, among other factors, the amount of equity capital to be raised and the relative trading prices of the LinnCo shares and the LINN units. Any proceeds from the sale of both LinnCo shares and LINN units will ultimately be used by LINN to execute its strategy.

Index to Financial Statements

Risk Factors

An investment in our shares involves risks. You should carefully consider the risks described in “Risk Factors” beginning on page 29 of this prospectus and the other information in this prospectus before deciding whether to invest in our shares.

Risks Related to LINN’s Business

LINN actively seeks to acquire oil and natural gas properties. Acquisitions involve potential risks that could adversely impact its future growth and its ability to increase or pay distributions at the current level, or at all.development cost efficiencies.

 

LINN has significant indebtedness. LINN’s revolving credit facility and the indentures governing LINN’s outstanding senior notes have substantial restrictions, and LINN may have difficulty obtaining additional credit, which could adversely affect its operations, its ability to make acquisitions and its ability to pay distributions to its unitholders, including us.

Commodity prices are volatile, and a significant decline in commodity prices for a prolonged period would reduce LINN’s revenues, cash flow from operations and profitability and it may have to lower its distribution or may not be able to pay distributions at all, which would in turn reduce or eliminate our ability to pay dividends to you.

LINN’s estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of LINN’s reserves.

LINN’s development operations require substantial capital expenditures, which will reduce its cash available for distribution. LINN may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in its reserves.

Drilling for and producing oil, natural gas and NGL are high risk activities with many uncertainties that could adversely affect LINN’s financial position or results of operations and, as a result, its ability to pay distributions to its unitholders.

LargelyRisks Inherent in an Investment in LinnCoHeld-by-Production.

Because our only assets will be LINN units, our cash flow and our ability to pay dividends on our shares are completely dependent upon the ability of LINN to make distributions to its unitholders.

We will incur corporate income tax liabilities on income allocated to us by LINN with respect to LINN units we own, which may be substantial.

An active trading market for our shares may not develop, and even if such a market does develop, the market priceApproximately 84% of our shares may be less than the price you paid for your shares and less than the market pricetotal acreage position washeld-by-production (“HBP”) as of LINN units.

Our shareholders will only be ableDecember 31, 2018. We expect this high percentage of HBP acreage to indirectly vote on matters on which LINN unitholders are entitled to vote, and our shareholders are not entitled to vote to elect our directors. Therefore, you will only be able to indirectly influence the management and board of directors of LINN, and you will not be able to directly influence or change our management or board of directors.

LINN may issue additional units or other classes of units, and we may issue additional shares without your approval, which would dilute our direct and your indirect ownership interest in LINN and your ownership interest in us.

Index to Financial Statements

Your shares are subject to limited call rights that could result in your having to involuntarily sell your shares at a time or price that may be undesirable.

Our limited liability company agreement limits the fiduciary duties owed by our officers and directors to our shareholders, and LINN’s limited liability company agreement limits the fiduciary duties owed by LINN’s officers and directors to its unitholders, including us.

The terms of our shares may be changed in ways you may not like, because our board of directors will have the power to change the terms of our shares in ways our board determines, in its sole discretion, are not materially adverse to you.

Our shares may trade at a substantial discount to the trading price of LINN units.

Tax Risks to Shareholders

If LINN were subject to a material amount of entity-level income taxes or similar taxes, whether as a result of being treated as a corporation for U.S. federal income tax purposes or otherwise, the value of LINN units would be substantially reduced and, as a result, the value of our shares could be substantially reduced.

Management of LinnCo

LINN owns our sole voting share (the “voting share,” and collectively with any additional shares of the same class issued in the future, the “voting shares”) and will be entitled to elect our entire board of directors.

Our initial board of directors will be identical to LINN’s board of directors, and all of our officers are also officers of LINN. Our shareholders will be able to indirectly vote on matters on which LINN unitholders are entitled to vote. Our shareholders are not entitled to vote to elect our directors. Under NASDAQ’s listing rules, we are considered a “controlled company” such that our board of directors will be exempt from the requirement that it have a majority of independent directors meeting the NASDAQ’s independence standards. We will, however, be required to have an audit committee of the board of directors composed entirely of independent directors. At the completion of this offering, our board of directors will be comprised of seven directors, including five independent directors constituting our audit committee. For information about our executive officers and directors, please read “Management” beginning on page 106.

Comparison of LINN Units with LinnCo Shares

You should be aware of the following ways in which an investment in LINN units is different from an investmentenhance capital efficiencies in our shares. development program, as we will pursue development locations with the favorable risk-adjusted rates of return in our location selection process, as opposed to selecting locations in order to hold acreage.



The table below should be read together with “Descriptionprovides a summary of Our Shares,” “Descriptionour acreage position as of the LINN Units,” Description of the Limited Liability Company Agreements,” and “Material U.S. Federal Income Tax Consequences.”December 31, 2018:

 

   

LINN Units

Total
 

LinnCo Shares

Business and Assets

Operated Sections

LINN is in the business of acquiring and developing oil and natural gas assets.Our sole purpose is to own LINN units. We will not have any other assets at closing and do not intend to own assets other than LINN units and reserves for income taxes payable by us. As a result, our financial condition and results of operations will depend entirely on the performance of LINN.

Index to Financial Statements
   

LINN Units

313
 

LinnCo Shares

VotingUnitholders have the right to vote with respect to the election of LINN’s board of directors, certain amendments to its limited liability company agreement, the merger of LINN or the sale of all or substantially all of its assets and the dissolution and winding up of LINN.

We will submit to a vote of our shareholders any matter submitted by LINN to a vote of its unitholders. We will vote the LINN units that we hold in the same manner as the owners of our shares vote (or refrain from voting) their shares on those matters. In addition, our shareholders will be entitled to vote on certain fundamental matters affecting us, such as certain amendments to our limited liability company agreement or the Omnibus Agreement (as defined below), certain mergers, the sale of all or substantially all of our assets and our dissolution and winding up.

LINN, as the holder of our sole voting share, will have the right to elect the members of our board of directors, and our shareholders will have no right to vote in that election.

Board of Directors and OfficersOperated Acres

LINN’s business and affairs are managed under the direction of LINN’s board of directors, which has the power to appoint our officers.

The authority and function of LINN’s board of directors and officers is, with certain exceptions, identical to the authority and functions of a board of directors and officers of a corporation organized under the General Corporation Law of the State of Delaware, or DGCL.

Our initial board of directors will be composed of the same members as LINN’s board of directors, and our initial officers will be the same individuals who serve as officers of LINN.

Our business and affairs will be managed under the direction of our board of directors, which has the power to appoint our officers.

The authority and function of our board of directors and officers will be identical to the authority and functions of a board of directors and officers of a corporation organized under the DGCL, except for certain limitations on their fiduciary duties.

Index to Financial Statements
   

LINN Units

122,254
 

LinnCo Shares

Distributions and DividendsNon-Operated Acres

On a quarterly basis, LINN is required to distribute to the owners of its units an amount equal to its available cash.

On a quarterly basis, LinnCo is required to pay a dividend equal to the amount of cash received from LINN in respect of the LINN units owned by LinnCo, less reserves for income taxes payable by LinnCo.

We will incur corporate income tax liability on income allocated to us by LINN with respect to LINN units we own. Accordingly, the quarterly cash dividend you receive will be less than the quarterly per unit distribution of cash that we receive from LINN. For the periods ending December 31, 2012, 2013, 2014 and 2015, we estimate that LinnCo’s income tax liability will not exceed     % of the cash distributed to LinnCo.

Income Tax

LINN is taxed as a partnership for U.S. federal income tax purposes.

Although LINN is not subject to entity level federal income tax, each unitholder is required to report as income his allocable share of LINN’s income, gains, losses and deductions for LINN’s taxable year or years ending with or within his taxable year.

Our federal taxable income will be subject to a corporate level tax at a maximum rate of 35%, under current law (and a 20% alternative minimum tax on our alternative minimum taxable income in certain cases), and we may be liable for state income taxes at varying rates in states in which LINN operates.

Our shareholders will be subject to U.S. federal income tax, as well as any applicable state or local income tax, on taxable dividends received by them, or on any gain when they sell our shares. Our shareholders will not report our items of income, gain, loss and deduction on their U.S. federal income tax returns. We estimate that if you own the shares that you purchase in this offering through December 31, 2015, you will recognize, on a cumulative basis, an amount of taxable dividend income that will be     % or less of the cash dividends paid to you during that period. The excess of the cash dividends that you receive over your taxable dividend income during that period will reduce your tax basis in your shares.

Index to Financial Statements
   

LINN Units

49,717
 

LinnCo Shares

Taxation Schedules

Unitholders receive a Schedule K-1 from LINN reflecting the unitholders’ share of LINN’s items of income, gain, loss, and deduction.

Any net income or gain of LINN allocated to a tax-exempt organization, including an employee benefit plan, will constitute unrelated business taxable income of that organization.

Like shareholders of a corporation, LinnCo shareholders will receive a Form 1099-DIV reflecting dividends of cash or other property we paid to them. Our shareholders will not receive a Schedule K-1 from us because they will not be allocated our items of income, gain, loss, and deduction.

A tax-exempt organization, including an employee benefit plan, generally will not have unrelated business taxable income upon the receipt of dividends from us.

  

Net income and gain from LINN units generally will be qualifying income to a regulated investment company or mutual fund, subject to certain limitations that do not apply to income or gain with respect to stock of a corporation.

 

 

Dividend income and gain from our shares generally will be qualifying income to a regulated investment company or mutual fund.Total Acres

171,970

% HBP

84

% Operated

71

Our Drilling Program and Completion Techniques

IndexWe intend to Financial Statements

Ownershiptarget accretive growth in production and cash flow by developing and expanding our significant portfolio of LINNdrilling locations. We believe that our recent well results demonstrate that many of our development projects are capable of producing attractive rates of return that are competitive with many of the top performing basins in the United States. We are focused on drilling wells with high rates of return, repeatable production profiles and increasing estimated ultimate recoveries (“EURs”) while at the same time seeking to capitalize on drilling, completion and operating efficiencies. Our management team assumed operation of our properties in the first half of 2018 and has achieved meaningful operational advancements, including (i) improvement in lateral targeting, (ii) reductions in development cycle times, (iii) optimization testing of well completion methods, (iv) well flowback management, and (v) expanded subsurface data coverage, including3-D seismic.

Reserves Information

The following diagram depicts LINN’stable provides summary information regarding our proved reserves as of December 31, 2018, based on a reserve report prepared by DeGolyer and MacNaughton,our independent reserve engineers (“DeGolyer and MacNaughton”).

Estimated Total Proved Reserves

Oil
(MMBbls)

  NGLs
(MMBbls)
  Natural
Gas (Bcf)
  Total
(MMBoe)
  PV-10
($)(1)(2)
  %
Oil
  %
Liquids
  %
Developed

55.7

  98.4  911.2  306.0  2,091,509  18.2  50.4  39.3

(1)

Presented in thousands.PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Please see “Risk Factors—The standardized measure of our estimated reserves contained in this prospectus and in the footnotes to our financial statements is not an accurate estimate of the current fair value of our estimated reserves.” NeitherPV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry usePV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Please see “Summary Historical and Unaudited Pro Forma FinancialData—Non-GAAP FinancialMeasure—PV-10”.

(2)

Our estimated net proved reserves were determined using averagefirst-day-of-the-month prices for the prior 12 months in accordance with SEC guidance adjusted for quality, transportation fees, regional price differentials, and in the case of natural gas, energy content. For oil and NGLs volumes, the average WTI posted price of $65.66 per barrel as of December 31, 2018, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average



Henry Hub spot price of $3.16 per MMBtu as of December 31, 2018, was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.49 per barrel of oil, $20.35 per barrel of NGLs and $1.90 per Mcf of natural gas as of December 31, 2018.

Our Business Strategies

Our primary objective is to maximize shareholder value across business cycles by pursuing the following strategies:

Generate attractive full-cycle returns through the efficient development of our extensive,low-risk drilling inventory.We intend to efficiently achieve industry leading rates of return by leveraging the scale of our core leasehold positions, experience from the success of our drilling program to date, technical understanding of the reservoirs, our extensive catalogue of technical information and experience of our operational teams. We intend to allocate capital in a disciplined manner to projects that we believe will produce predictable and attractive full-cycle rates of return. We consider our extensive inventory of high-potential, oil and liquids-weighted drilling locations to be relativelylow-risk based on information gathered from over 400 horizontal wells developed since early 2014, of which 152 were drilled by us or our predecessors as of December 31, 2018, and over 4,450 vertical wells developed in our development area, industry activity surrounding our acreage, subsurface data, including well cores and logs and3-D seismic and the consistent geology surrounding our position.

Maximize value of our asset base through constant focus on improving operating, production and capital efficiencies.We utilize proprietary data analytics, combined with operational procedures and metrics, to evaluate well results and adjust drilling and production techniques in real time. We use this framework in an effort to maximize hydrocarbon recoveries per well by optimizing location selection, wellbore targeting, well completion designs and production techniques.Our management and technical teams intend to apply their operational expertise, data gained from our large acreage position in the Merge play and available third-party data to deploy advanced drilling, completion and production management technologies that maximize well productivity and control capital and operating costs. Additionally, we seek to reduce capital and operating costs of drilling and completing horizontal wells by decreasing development cycle times, optimizing the use of surface facilities, capitalizing on our knowledge of the target formations and focusing on service cost management practices. Our highly experienced management and technical teams have a substantial track record of developing unconventional plays, which we believe is instrumental in our achievement of these operational and capital efficiencies.

Maintain a high degree of operational control to facilitate efficient development and capital budgeting.We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As of December 31, 2018, we operated approximately 71% of our total acreage. We believe that maintaining a high degree of control of the development of our properties and of our production enables us to increase hydrocarbon recovery rates, lower capital and operating costs and improve drilling performance through optimization of our drilling, completion and production management techniques. Additionally, we believe operatorship allows us to control wellsite selection, spacing and lateral targeting and manage the pace of our development activities, which we believe can significantly enhance full-cycle returns. We will adjust the size of our rig program to optimize our overall development program and with a view to limiting the lag time between the development of parent and child wells. Through these measures, we seek to target an optimal combination of net present value and



rate of return associated with the development of a particular unit. According to RS Energy Group, child wells are generally at least 25% more productive if drilled within 1.5 years of the development of the parent well, as compared to child wells drilled 1.5 to 3 years following the development of the parent well. Operational and developmental control positions us to minimize the adverse impacts associated with this time lag.

Maintain a disciplined, returns-driven strategy with a focus on maintaining financial flexibility.We intend to maintain a conservative financial profile that will afford us flexibility through the commodity price and capital market cycles inherent in the oil and natural gas industry. We intend to generate stable production and reserves growth by funding our development program primarily with cash flow from operations, borrowings under our credit facility and capital markets offerings. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price volatility, enabling us to protect future cash flows and maintain liquidity to fund our development program.

Selectively pursue opportunities to augment our asset base through the disciplined acquisition or leasing of oil and natural gas properties. We believe we are well positioned to selectively pursue accretive consolidation opportunities. We believe the strength of our operational program provides a competitive advantage in the pursuit of such opportunities. We will continue to identify and evaluate acquisition and leasing opportunities around and within our concentrated acreage position, as well as other areas in Oklahoma, that meet our strategic and financial objectives.

Our Competitive Strengths

We believe the following strengths will allow us to successfully execute on our business strategies:

Large, contiguous acreage position in the core of the Merge play with significant operational control.We are the largest leaseholder in the Merge play, with approximately 115,000 net acres as of December 31, 2018. We believe that the scale and concentration of our acreage position allows for efficient field development through long laterals and shared facilities, with approximately 80% of our Merge sections capable of 1.5 mile or longer lateral development. Additionally, our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs within the Merge play, and provides us development opportunities through multiple stacked prospective development horizons. As of December 31, 2018, we operated 81% of our net acreage in the Merge and we intend to maintain operational control over the majority of our drilling inventory, as we believe this enables us to increase our production and reserves and control our development costs, and ultimately increase shareholder value. Operatorship of our position allows us the flexibility to control the pace of our development plan, as well as the lengths of our laterals and our drilling and well completion techniques.

Long-lived inventory of locations with predictable production profiles that provide highrate-of-return development opportunities.Through the drilling of over 163 operated horizontal wells and participation in over 317non-operated horizontal wells as of December 31, 2018 across our acreage, we have substantially delineated our acreage and have acquired significant amounts of subsurface information. Based on this delineation and general industry Merge, SCOOP and STACK well production history, we believe that our acreage position will provide a large portfolio of drilling locations characterized by long-lived reserves, predictable production profiles and attractive return potential.

Geographically advantaged assets with significant available midstream infrastructure and favorable regulatory climate.Our acreage position is in close proximity or has available access to end markets for oil, natural gas and NGLs providing us with a regional price advantage relative to other U.S.



onshoreoil-weighted basins. While oil represents a significant portion of our total revenues, natural gas and NGLs comprise a majority of our reserves and production. While we believe we have favorable realized price differentials for natural gas and NGLs compared to other basins, our realized natural gas price differential is based on the sales price at multiple hubs and our NGLs are sold on a product by product basis. Oklahoma has a long history of oil and natural gas production, and therefore there is existing midstream infrastructure in place across our acreage position to support our drilling program. In addition, we believe that oilfield services availability is greater in our focus area than in other major U.S. onshore basins and that such availability is a competitive advantage in assuring the ability to access necessary development services at attractive pricing.

Experienced operations leadership with substantial technical expertise. We believe our operational management team provides us with a distinct competitive advantage. Our team has significant experience working together throughout theMid-Continent and evaluating the Merge play in particular. Joel Pettit, our Executive Vice President – Operations and Marketing, worked in EOG’sMid-Continent Division for over a decade. Greg Condray, our Executive Vice President – Geosciences and Business Development, worked with Mr. Pettit in EOG’sMid-Continent Division as Division Exploration Manager, and had considerable experience at Chesapeake Energy leading initial delineation and development efforts in the Eagle Ford, Haynesville and Powder River Basin. We believe their experience is instrumental in the execution of our pursuit of operational and capital efficiencies.

Significant financial strength and flexibility. We believe we have a strong financial position, including a low debt profile and a large production base that generates significant cash flow, allowing us to strategically allocate capital in order to enhance shareholder value. We are well-positioned to adjust our development program based on market and industry conditions, as we have minimal commitments to deliver specified volumes, no rig contracts extending beyond 12 months and approximately 84% of our acreage is held by production as of December 31, 2018. We believe that our conservative capital structure, which we will seek to maintain through a disciplined approach to capital spending, and other potential financing sources will provide us with sufficient liquidity and flexibility to execute our development capital program.

Historical Capital Expenditures and Capital Budget

Our 2019 capital budget is approximately $515 million to $555 million. During the three months ended March 31, 2019, capital expenditures were approximately $173.6 million. We expect our 2019 capital budget to be more heavily weighted in the first half of the year as a result of increased completion activity as we develop our inventory of drilled but uncompleted wells from 2018.

Because we are the operator of a high percentage of our acreage and a majority of our acreage is held by production, the amount and timing of our capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, and prevailing and anticipated prices for oil and natural gas. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows and loss of acreage through lease expirations.



In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

Recent Developments

History and Reorganization

Our predecessor, Roan LLC, was initially formed by Citizen in May 2017. In June 2017, subsidiaries of Old Linn, together with Citizen and Roan LLC entered into a contribution agreement pursuant to which, among other things, Old Linn and Citizen agreed to contribute certain oil and natural gas assets to Roan LLC (the “Contribution”), each in exchange for a 50% equity interest in Roan LLC. On August 31, 2017, Old Linn and Citizen consummated the transactions contemplated by such contribution agreement. Following these transactions, Citizen’s equity interest in Roan LLC was held through its wholly owned subsidiary, Roan Holdings.

In the third quarter of 2018, Old Linn and certain of its subsidiaries undertook an internal reorganization, pursuant to which Old Linn merged with and into a wholly owned subsidiary of New Linn. Following such internal reorganization, New Linn completed thespin-off of substantially all of its assets, other than its 50% equity interest in Roan LLC.

On September 17, 2018, New Linn, Roan Holdings and Roan LLC entered into a Master Reorganization Agreement (the “Master Reorganization Agreement”), to effectuate the reorganization of New Linn’s and Roan Holdings’ respective 50% equity interests in Roan LLC under Roan Resources, Inc. On September 24, 2018, the Company consummated the Reorganization, which resulted in the existing stockholders of New Linn receiving 50% of the Class A common stock of the Company and Roan Holdings receiving 50% of the Class A common stock of the Company.In connection with the Reorganization, the Company became the owner, indirectly through its wholly-owned subsidiaries, of 100% of the equity in, and is the sole manager of, Roan LLC. The Company is responsible for all operational, management and administrative decisions relating to Roan LLC’s business.



The following chart provides a simplified overview of our organizational and ownership structure after giving effect to this offering and to the subsequent purchase of LINN units by us.Reorganization.

 

Public Units (             )

Units held by LinnCo (            )

Total

100

LOGO

LOGOOn November 9, 2018, the Company’s Class A common stock began trading on the NYSE under the symbol “ROAN.”

Credit Facility Amendment

*Held by a wholly-owned subsidiary of Linn Energy, LLC.

Principal Executive OfficesOn March 13, 2019, the Company amended its existing credit agreement, dated as of September 5, 2017 (as amended, amended and Internet Addressrestated, supplemented or otherwise modified from time to time, our “credit facility”) to, among other things, (i) increase the borrowing base under the credit facility to $750 million, provided that there will be no reduction of the borrowing base in connection with the issuance of any Permitted Additional Debt (as defined in the credit facility) for the first (x) $400 million in principal of such unsecured Permitted Additional Debt and (y) $250 million in principal of such secured Permitted Additional Debt and (ii) permit certain additional restricted payments to be made. As of March 31, 2019, our outstanding borrowings under the credit facility were $602.6 million with available borrowing capacity of $147.4 million and a cash balance of $2.2 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility.”

Risk Factors

Investing in our Class A common stock involves risks. You should carefully read and consider the section of this prospectus titled “Risk Factors” beginning on page 18 and all other information in this prospectus before investing in our Class A common stock.

Corporate Information

Our principal executive offices are located at 600 Travis, Suite 5100, Houston, Texas 77002,14701 Hertz Quail Springs Pkwy, Oklahoma City, Oklahoma 73134, and our telephone number at that address is (281) 840-4000.(405)896-8050. Our website is located atwww.www.roanresources.com..com and will be activated immediately following this offering. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission which we refer to as the SEC,(the “SEC”) available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference hereininto this prospectus and does not constitute a part of this prospectus.



Index to Financial Statements

The Offering

 

LinnCo

We are a Delaware limited liability company recently formed to hold units of LINN.

SharesClass A common stock offered toby the public

selling stockholders
                 shares, or                 shares if the underwriters exercise their option to purchase additional shares in full.

Shares outstanding after this offering

                shares (or                 shares if the underwriters exercise their option to purchase additional shares in full) representing a 100% economic interest in us.

  One voting share of LinnCo owned by LINN. Our voting share is a non-economic interest.117,139,511 shares.

LINN units held by LinnCo after this offering

Class A common stock outstanding  units (or                 units if the underwriters exercise their option to purchase additional shares in full) representing a     % limited liability company interest in LINN.152,539,532 shares.

Use of proceeds

We will use all of the netnot receive any proceeds from this offering of approximately $         million ($         million if the underwriters exercise their option to purchase additional shares in full), after deducting underwriting discounts, to purchase from LINN a number of LINN units equal to the number of shares sold in this offering. LINN will pay the expenses of this offering.

LINN will use the proceeds it receives from the sale of LINN units to us for general corporate purposes, including financing its acquisition strategy, repaying debt and payingshares by the expensesselling stockholders. Please see “Use of this offering.Proceeds.”

Dividend policy  Affiliates of certain of the underwriters in this offering are lenders under LINN’s revolvingWe do not anticipate paying any cash dividends on our Class A common stock. In addition, our credit facility and, accordingly, if LINN electsplaces certain restrictions on our ability to use the proceeds it receives from LinnCo to repay any such debt outstanding under that facility, those lenders would indirectly receive a portion of the net proceeds from this offering.pay cash dividends. Please read “Underwriting—FINRA Rules.see “Dividend Policy.

Proposed NASDAQ

Listing and trading symbol

We intend to apply to list the sharesOur Class A common stock trades on the NASDAQ Global Select MarketNYSE under the symbol “LNCO.“ROAN.

Our dividend policy

Our limited liability company agreement requires us to pay dividends on our shares of the cash we receive as distributions in respect of our LINN units, net of reserves for income taxes payable by us, within five business days after we receive such distributions.

LINN distribution policy

Risk factors
LINN’s limited liability company agreement requires it to make quarterly distributions to unitholders of all of its “available cash,” which is defined to mean, for each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash reserves established by the LINN board of directors to:

provide for the proper conduct of business (including reserves for future capital expenditures, future debt service requirements, and for anticipated credit needs); and

Index to Financial Statements

comply with applicable laws, debt instruments or other agreements;

  plusYou should carefully read and consider the information set forth under the heading “Risk Factors” and all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.

U.S. federal income tax matters associated with our shares

Because we will be treated as a corporation for U.S. federal income tax purposes, our shareholders will receive a Form 1099-DIV and will be subject to federal income tax, as well as any applicable state or local income tax, on taxable dividends paid to them. An owner of our shares will not report on its U.S. federal income tax return any of our items of income, gain, loss and deduction. An owner of our shares will not receive a Schedule K-1 and will not be subject to state tax filings in the various states in which LINN conducts business as a result of owning our shares. A tax-exempt investor’s ownership or sale of our shares generally will not generate income derived from an unrelated trade or business regularly carried on by the tax-exempt investor, which generally is referred to as unrelated business taxable income, or “UBTI.” The ownership or sale of our shares by a regulated investment company, or mutual fund, will generate qualifying income to it. Furthermore, the ownership of our shares by a mutual fund will be treated as a qualifying asset. There generally will be no taxes imposed on gain from the sale of our shares by a non-U.S. person provided it has owned no more than 5% of our shares and our shares are regularly traded on a nationally recognized securities exchange. Dividends to non-U.S. persons will be subject to withholding tax of 30% (or a lower treaty rate, if applicable). See “Material U.S. Federal Income Tax Consequences.”

Our covenants

Our limited liability company agreement provides that our activities will be limited to owning LINN units. It requires that our issuance of shares of classes other than (i) the class of shares being soldinformation set forth in this offering and (ii) the class of voting shares currently owned by LINN, be approved by the owners ofprospectus before deciding to invest in our outstanding shares, voting as separate classes, and further includes covenants that prohibit us from (otherwise than in connection with a Terminal Transaction):Class A common stock.


borrowing moneySummary Historical and Unaudited Pro Forma Financial Data

Roan Resources, Inc. was incorporated in September 2018 to serve as a holding company and, prior to the Reorganization, had no previous operations, assets or issuing debt;

selling, pledging or otherwise transferring any LINN units;

issuing options, warrants or other securities entitlingliabilities. The historical financial information included in this prospectus (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is that of Roan LLC, our predecessor. The historical financial and operational information of Roan LLC presented in this prospectus, (i) prior to August 31, 2017, the holderdate of the completion of the Contribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the historical financial and operational information of Citizen prior to purchase our shares, exceptAugust 31, 2017 does not include financial information relating to the oil and natural gas assets contributed to Roan LLC by Old Linn in connection with employee benefit plans;

liquidating, merging or recapitalizing;

revoking or changing our election to be treated as a corporation for U.S. federal income tax purposes; or

using the proceeds from sales of our shares other than to purchase LINN units.

Index to Financial Statements
See “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement.” In addition, these provisions can be amended or waived by the owners of our shares as described under “—Voting rights” below.

Relationship with LINN

Under our limited liability company agreement, LINN has agreed that neither it nor any of its subsidiaries will take any action that would result in LINN and its subsidiaries ceasing to control LinnCo, except in connection with a Terminal Transaction.

Under an Omnibus Agreement between LINN and us (the “Omnibus Agreement”), LINN will pay on our behalf (directly or indirectly) any legal, accounting, tax advisory, financial advisory and engineering fees, printing costs or other administrative and out-of-pocket expenses we incur, along with any other expenses incurred in connection with this offering or incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and other reports to holders of our shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, independent auditor fees and registrar and transfer agent fees. LINN will also agree to indemnify us for damages suffered or costs incurred (other than income taxes payable by us) in connection with carrying out our activities.

These covenants can be amended or waived by the owners of our shares as described under “—Voting rights” below.

Terminal Transactions involving LINN

Mergers. If the LINN unitholders are asked to approve a merger of LINN with another entity, we will submit the merger to a vote of our shareholders and will vote our LINN units in the same manner that our shareholders vote (or refrain from voting) their shares.

Cash Consideration. In a merger involving LINN in which unitholders receive cash, you will be entitled to receive any cash we receive for our LINN units, net of income taxes payable by us. In the event of an all-cash merger of LINN, we will dissolve and wind up our affairs after such distribution.

Non-Cash Consideration. In a merger involving LINN in which LINN unitholders receive securities of another entity, you will be entitled to receive the securities received in connection with such merger. In the event of such a merger in which LINN is not the surviving entity, we will dissolve and wind up our affairs unless:

LINN’s successor would be treated as a partnership for U.S. federal income tax purposes; and

the surviving entity agrees to assume the obligations of LINN under our limited liability company agreement and the Omnibus Agreement.

Index to Financial Statements
Tender Offers.If a third party makes a tender offer for LINN units, LINN may, but will not be obligated to, cooperate with such third party to extend such tender offer to our shareholders or otherwise facilitate participation of our shareholders in the tender offer for LINN units.

Going Private Transaction. If at any time a person owns more than 90% of the outstanding LINN units, such person may elect to purchase all, but not less than all, of the remaining outstanding LINN units at a price equal to the higher of the current market price (as defined in LINN’s limited liability company agreement) and the highest price paid by such person or any of its affiliates for any LINN units purchased during the 90-day period preceding the date notice was mailed to the LINN unitholders informing them of such election. In this case, we will be required to tender all of our outstanding LINN units and distribute the cash we receive, net of income taxes payable by us, to our shareholders. Following such distribution, we will cancel all of our outstanding shares and dissolve and wind up our affairs.

Sale of All or Substantially All of LINN’s Assets.If LINN sells all or substantially all of its assets in one or more transactions for cash and makes a distribution of such cash to its unitholders, we will distribute the cash we receive, net of income taxes payable by us, to our shareholders. Following such distribution, we will cancel all of our outstanding shares and dissolve and wind up our affairs.

Change in Tax Treatment of LINN. If LINN or its successor ceases to be treated as a partnership for U.S. federal income tax purposes, LINN or such successor will have the right to cause us to merge with and into LINN, in which case each of our shareholders will receive distributions in kind of LINN units and other property we own, if any, after payments to creditors and satisfaction of other obligations.

The transactions described above are referred to as “Terminal Transactions.”

Limited call rights

If LINN or any of its affiliates owns 80% or more of our outstanding shares, LINN has the right, which it may assign to any of its affiliates, to purchase all of our outstanding shares, at a purchase price not less than the then-current market price of our shares.

If any person acquires more than 90% of the outstanding LINN units, such person may require us to tender all of our outstanding LINN units, in which case we will distribute the cash we receive to our shareholders. Following such distribution, we will cancel all of our outstanding shares and dissolve and wind up our affairs. See “—Terminal Transactions involving LINN” above.

Index to Financial Statements

Voting rights

We will submit to a vote of the owners of our shares any matter submitted to us by LINN for a vote of the LINN units held by us. We will vote the LINN units that we own in the same manner that the owners of our shares vote (or refrain from voting) their shares. The LINN units we hold will have the same voting rights as all other LINN units.

Owners of the shares being sold in this offering will have no right to elect our directors. LINN owns the sole voting share entitled to elect our directors, which we refer to as the “voting share,” and which has no economic interest in us. Owners of the shares of the class being sold in this offering are entitled to vote on the following matters related to us:

amendments to our limited liability company agreement and the Omnibus Agreement with LINN, but only if the amendment would have a material adverse effect on the preferences or rights of our shareholders (as determined in the sole discretion of our board of directors), would reduce the time for any notice to which the owners of our shares are entitled, enlarges the obligations of our shareholders, alters the circumstances under which LinnCo could be dissolved or wound up or changes the term of existence of LinnCo;

an amendment or waiver of LINN’s covenant regarding its continued ownership of more than 50% of the total voting power of LinnCo;

an amendment or waiver of the covenants described above under “Our covenants”;

our issuance of classes of shares other than shares of the class being sold in this offering and the class of the voting share currently owned by LINN;

a merger of LinnCo or the sale of all or substantially all of our assets (other than in connection with a Terminal Transaction); and

our dissolution (other than in connection with a Terminal Transaction).

The matters described above, other than amendment or waiver of the covenants described above under “Our covenants,” also require approval by the holders of a majority of our voting shares.

Ratio of LinnCo shares to LINN units

Our limited liability company agreement requires that the number of our outstanding shares and the number of LINN units we own always be equal.

Index to Financial Statements

Summary Historical and Pro Forma Financial and Operating Data of LINNContribution.

The following table shows summary historical and pro forma financial and operatingstatement of operations data of LINN as of the dates and for the periods indicated. The selected historical financial data presented as of December 31, 2010 and 2011 and for the years ended December 31, 2009, 20102018, 2017 and 2011 are2016 was derived from the audited historical audited financial statements that areof Roan Inc. included elsewhere in this prospectus. The selectedsummary historical balance sheet data as of December 31, 2018 and 2017 was derived from the audited historical financial datastatements of LINN presentedRoan Inc. included elsewhere in this prospectus. The summary unaudited historical interim condensed financial data as of March 31, 2012 and for the three months ended March 31, 20112019 and 2012 are2018 was derived from theour unaudited interim condensed financial statements that are included elsewhere in this prospectus. The summary pro formaunaudited historical condensed interim financial data presentedhas been prepared on a consistent basis with the audited financial statements of Roan Inc. In the opinion of management, such summary unaudited historical condensed interim financial data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the year ended December 31, 2011 and the three months ended March 31, 2012 are derived from the unaudited pro forma condensed combined financial statements that are included elsewhere in this prospectus.periods presented. The pro forma financial data presentedresults of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year ended December 31, 2011because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the three months ended March 31, 2012 give effect touncertainty of exploration and development drilling results and other factors.

Our historical results are not necessarily indicative of future results. You should read the Hugoton Acquisition and certain other 2011 acquisitions. The following table should be read togetherin conjunction with “Selected Historical and is qualified in its entirety by reference to, the historical and unaudited financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together withUnaudited Pro Forma Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The unauditedOperations” and the historical and pro forma financial statements do not purport to represent what LINN’s results of operations would have actually been had the Hugoton Acquisition occurred on the dates noted above, or to project LINN’s results of operations as of any future date or for any future periods. and accompanying notes included elsewhere in this prospectus.

The pro forma adjustments are based on available information and certain assumptions that LINN believes are reasonable. The adjustments are directly attributable to the acquisition of oil and natural gas properties from the Hugoton Acquisition included and are expected to have a continuing impact on LINN’s results of operations. In our opinion, all adjustments necessary to present fairly thesummary unaudited pro forma condensed combined financial statements have been made.

Index to Financial Statements

Because of rapid growth through acquisitions and development of properties, LINN’s historical resultsstatement of operations and period-to-period comparisons of these results and certain other financial data may not be meaningful or indicative of future results. The results of LINN’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations, which were disposed of in 2008, are classified as discontinued operations, due to post-closing adjustments, for the year ended December 31, 2009. Unless otherwise2018 has been prepared to give pro forma effect to the Reorganization as if it had occurred on January 1, 2018. The summary unaudited pro forma condensed financial data is provided for illustrative purposes only and is not indicative of the results that actually would have occurred had the transactions been in effect on the dates or for the periods indicated, or of results of operations information presented herein relates only to continuing operations.that may occur in the future.



  Historical  Pro Forma  Historical  Pro Forma 
  At or for the Year Ended
December 31,
  For the Year
Ended
December 31,
  At or for the Three
Months Ended
March 31,
  For the  Three
Months
Ended

March 31,
 
  2009  2010  2011  2011  2011  2012  2012 
           (Unaudited)  (Unaudited)  (Unaudited) 
  (in thousands, except per unit amounts) 

Statement of operations data:

       

Oil, natural gas and natural gas liquids sales

 $408,219   $690,054   $1,162,037   $1,649,701   $240,707   $348,895   $405,777  

Gains (losses) on oil and natural gas derivatives

  (141,374  75,211    449,940    449,940    (369,476  2,031    2,031  

Depreciation, depletion and amortization

  201,782    238,532    334,084    436,786    66,366    117,276    133,924  

Interest expense, net of amounts capitalized

  92,701    193,510    259,725    359,547    63,464    77,519    96,906  

Income (loss) from continuing operations

  (295,841  (114,288  438,439    532,939    (446,682  (6,202  (16,667

Income (loss) from discontinued operations, net of taxes(1)

  (2,351  —      —      —      —      —      —    

Net income (loss)

  (298,192  (114,288  438,439    532,939    (446,682  (6,202  (16,667

Income (loss) per unit—continuing operations:

       

Basic

  (2.48  (0.80  2.52    3.04    (2.75  (0.04  (0.09

Diluted

  (2.48  (0.80  2.51    3.03    (2.75  (0.04  (0.09

Income (loss) per unit—discontinued operations:

       

Basic

  (0.02  —      —      —      —      —      —    

Diluted

  (0.02  —      —      —      —      —      —    

Net income (loss) per unit:

       

Basic

  (2.50  (0.80  2.52    3.04    (2.75  (0.04  (0.09

Diluted

  (2.50  (0.80  2.51    3.03    (2.75  (0.04  (0.09

Distributions declared per unit

  2.52    2.55    2.70     0.66    0.69   

Weighted average units outstanding

  119,307    142,535    172,004    173,728    163,107    193,256    193,256  
  Pro Forma  Three Months Ended
March 31,
  Year Ended December 31, 
  Year Ended
December 31,
2018
  2019  2018  2018  2017(1)  2016 
  (Unaudited)  (Unaudited)    
  

(in thousands, except per share data)

 

Statement of Operations Data:

    

Revenues(2):

      

Oil sales

 $275,239  $60,571  $63,692  $275,239  $76,876  $30,565 

Natural gas sales

  46,966   11,189   10,332   46,966   46,303   16,093 

Natural gas sales – Affiliates

  29,090   10,592   6,558   29,090   2,908   —   

Natural gas liquid sales

  51,467   8,338   11,939   51,467   35,217   8,307 

Natural gas liquid sales – Affiliates

  37,005   7,849   8,449   37,005   5,081   —   

Gain (loss) on derivative contracts

  78,054   (83,642  (9,614  78,054   (6,797  —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total revenues

  517,821   14,897   91,356   517,821   159,588   54,965 

Operating Expenses(2):

      

Production expenses

  47,600   14,846   8,355   47,600   16,872   5,090 

Gathering, transportation and processing

  —     —     —     —     18,602   5,920 

Production taxes

  17,579   5,039   2,386   17,579   3,685   1,087 

Exploration expenses

  43,303   12,488   7,850   43,303   32,629   5,258 

Depreciation, depletion, amortization and accretion

  123,922   41,572   21,865   123,922   37,376   24,996 

General and administrative

  56,297   15,825   14,020   60,874   31,357   5,581 

Gain on sale of assets

  —     (644  —     —     (838  —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total operating expenses

  288,701   89,106   54,476   293,278   139,683   47,932 

Total operating (loss) income

  229,120   (74,209  36,880   224,543   19,905   7,033 

Other income (expense):

      

Interest expense, net

  (8,352  (6,744  (1,799  (8,352  (1,461  (86

Other income

  —     —     —     —     13   —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net income before income taxes

  220,768   (80,953  35,081   216,191   18,457   6,947 

Income tax (benefit) expense(3)

  56,296   (22,897  —     356,862   —     —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net income(loss)

 $164,472  $(58,056 $35,081  $(140,671 $18,457  $6,947 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Earnings (loss) per share

      

Basic

 $1.08  $(0.38 $0.23  $(0.92 $0.18  $0.11 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Diluted

 $1.08  $(0.38)  $0.23  $(0.92 $0.18  $0.11 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Weighted average number of shares outstanding

      

Basic

  152,540   152,540   151,294   152,232   100,473   62,394 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Diluted

  152,540   152,540   151,294   152,232   100,473   62,394 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 


Index to Financial Statements
   Historical  Historical 
   At or for the Year Ended
December 31,
  At or for the Three
Months Ended March 31,
 
   2009  2010  2011  2011  2012 
   (in thousands)  (Unaudited)
(in thousands)
 

Cash flow data:

      

Net cash provided by (used in):

      

Operating activities(2)

  $426,804   $270,918   $518,706   $107,966   $35,513  

Investing activities

   (282,273  (1,581,408  (2,130,360  (358,068  (1,460,555

Financing activities

   (150,968  1,524,260    1,376,767    209,425    1,448,112  

Balance sheet data:

      

Total assets

  $4,340,256   $5,933,148   $8,000,137    $  9,577,092  

Long-term debt

   1,588,831    2,742,902    3,993,657     4,929,542  

Unitholders’ capital

   2,452,004    2,788,216    3,428,910     4,027,418  
  Pro Forma  Three Months Ended
March 31,
  Year Ended December 31, 
  Year Ended
December 31,
2018
  2019  2018  2018  2017(1)  2016 
  (Unaudited)  (Unaudited)    
  (In thousands) 

Balance Sheet Data (at period end):

      

Total assets

  $2,791,436   $2,749,109  $1,885,592                

Total liabilities

  $1,351,393   $1,254,075  $300,823                

Total equity

  $1,440,043   $1,495,034  $1,584,769                

Other Financial Data:

      

Adjusted EBITDAX(4)

 $299,342  $72,757  $73,986  $299,342  $96,711  $37,287 

Net Debt(4)

  $600,450   $507,756  $83,868  $13,147 

 

(1)Includes gains (losses) on sale of

On August 31, 2017, Old Linn contributed certain oil and natural gas assets net of taxes.to Roan LLC. The revenue and operating expenses associated with these assets for the period from contribution through December 31, 2017 is included in our results for the year ended December 31, 2017.

(2)Includes premiums paid for derivatives of approximately $94 million, $120 million

Revenue and $134 million for the years ended December 31, 2009, December 31, 2010 and December 31, 2011, respectively, and approximately $178 millionoperating expenses for the three months ended March 31, 2012.2019 and 2018 and the year ended December 31, 2018 reflects the adoption of Accounting Standards Codification Topic 606 Revenue from Contracts with Customers (“ASC 606”) on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

(3)

The pro forma data reflects pro forma tax expense based on the statutory tax rate of 25.5% at December 31, 2018 to prospective periods. As described under “Reorganization,” Roan Inc. was formed in conjunction with the Reorganization. Roan Inc. is taxable as a corporation under the Internal Revenue Code of 1986, as amended (the “Code”), and as a result, is subject to U.S. federal, state and local income taxes. Our predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for federal income tax purposes, were deemed to pass to the members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of the members. The pro forma data excludes the income tax expense associated with the initial deferred tax liability recognized as a result of the Reorganization. The initial recording of the deferred tax liability has been reflected in the historical financial statements, but is not included in the pro forma data due to its non-recurring nature.

(4)

Adjusted EBITDAX and Net Debt arenon-GAAP financial measures. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss) and a reconciliation of Net Debt to long-term debt, please see“—Non-GAAP Financial Measure” below.

Non-GAAP Financial Measure

IndexAdjusted EBITDAX and Net Debt

Adjusted EBITDAX is a supplementalnon-GAAP financial measure that is used by management and other users of our financial statements. We define Adjusted EBITDAX as net income (loss) adjusted for interest expense, depreciation, depletion, amortization and accretion, income tax expense, exploration costs,non-cash equity-based compensation expense, gain on early termination of derivative contracts,non-cash (gain) loss on derivative contracts, reorganization transaction costs, expense for allowance for doubtful accounts and gain on sale of assets. Adjusted EBITDAX is not a measure of net income as determined by GAAP. Our predecessor, Roan LLC, passed through its taxable income to Financial Statements

Summary Reserveits owners for other income tax purposes and Operating Datathus, we have not incurred historical income tax expenses.



We believe Adjusted EBITDAX is useful because it allows our management to more effectively evaluate the operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We add the items listed above to net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX.

Net Debt is anon-GAAP financial measure equal to long-term debt outstanding less cash on hand as of the date presented. Our computations of Adjusted EBITDAX and Net Debt may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts. The following tabletables presents summary unaudited operating dataa reconciliation of Adjusted EBITDAX to net income (loss), and a reconciliation of Net Debt to long-term debt, our most directly comparable financial measures calculated and presented in accordance with respectGAAP for each of the periods indicated.

  Pro Forma          
  Year Ended
December 31,

2018
  Three Months Ended
March 31,
  Year Ended December 31, 
  2019  2018  2018  2017  2016 
     

(Unaudited)

          
  (in thousands) 

Adjusted EBITDAX reconciliation to net income (loss):

      

Net income (loss)

 $164,472  $(58,056 $35,081  $(140,671 $18,457  $6,947 

Interest expense

  8,352   6,744   1,799   8,352   1,461   86 

Income tax (benefit) expense

  56,296   (22,897  —     356,862   —     —   

Exploration expense

  43,303   12,488   7,850   43,303   32,629   5,258 

Non-cash equity-based compensation expense

  11,030   3,065   2,292   11,030   379   —   

Depletion, depreciation, amortization and accretion

  123,922   41,572   21,865   123,922   37,376   24,996 

Non-cash (gain) loss on derivatives contracts

  (111,333  89,024   5,099   (111,333  9,502   —   

Gain on early termination of derivative contracts

  —     —     —     —     (2,255  —   

Reorganization transaction costs

  —     —     —     4,577   —     —   

Allowance for doubtful accounts

  3,300   1,481   —     3,300   —     —   

Gain on sale of assets

  —     (664)   —     —     (838  —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted EBITDAX

 $299,342  $72,757  $73,986  $299,342  $96,711  $37,287 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

   As of March 31,   As of December 31, 
   2019   2018   2017 
       (in thousands) 

Net debt reconciliation to long-term debt:

      

Long-term debt

  $602,639   $514,639   $85,339 

Cash

   2,189    6,883    1,471 
  

 

 

   

 

 

   

 

 

 

Net Debt

  $600,450   $507,756   $83,868 
  

 

 

   

 

 

   

 

 

 


PV-10

PV-10 isa non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to LINN’s productionreflect the timing of future cash flows. Calculationof PV-10 does not give effect to derivatives transactions. Management believesthat PV-10 provides useful information to investors because it is widely used by professional analysts and sales ofsophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use ofa pre-tax measure is valuable for evaluating the periods presented and summary information with respect to LINN’s estimated proved oil and natural gas reserves at year end. DeGolyer and MacNaughton, independent petroleum engineers, provided the estimates of LINN’s proved oil and natural gas reserves as of December 31, 2009, 2010 and 2011 set forth below.

   Year Ended
December 31,
   Three Months Ended
March 31,
 
   2009   2010   2011       2011           2012     

Average daily production—continuing operations:

          

Natural gas (MMcf/d)

   125     137     175     158     229  

Oil (MBbls/d)

   9.0     13.1     21.5     17.2     26.1  

NGL (MBbls/d)

   6.5     8.3     10.8     8.6     14.2  

Total (MMcfe/d)

   218     265     369     312     471  

Weighted average prices (hedged):(1)

          

Natural gas ($/Mcf)

  $8.27    $8.52    $8.20    $8.99    $6.33  

Oil ($/Bbl)

   110.94     94.71     89.21     86.24     92.80  

NGL ($/Bbl)

   28.04     39.14     42.88     45.81     40.21  

Expenses ($/Mcfe):

          

Lease operating expenses

  $1.67    $1.64    $1.73    $1.63    $1.67  

Transportation expenses

   0.23     0.20     0.21     0.21     0.25  

General and administrative expenses(2)

   1.08     1.02     0.99     1.09     1.01  

Depreciation, depletion and amortization

   2.53     2.46     2.48     2.36     2.74  

Taxes, other than income taxes

   0.35     0.47     0.58     0.56     0.59  

   2009  2010  2011 

Estimated proved reserves—continuing operations:(3)

    

Natural gas (Bcf)

   774    1,233    1,675  

Oil (MMBbls)

   102    156    189  

NGL (MMBbls)

   54    71    94  

Total (Bcfe)

   1,712    2,597    3,370  

Percent proved developed reserves (%)

   71  64  60

Estimated reserve life (in years)(4)

   22    23    22  

Standardized measure of discounted future net cash flows ($ in millions)(5)

  $1,723   $4,224   $6,615  

(1)Includes the effect of realized gains on derivatives of approximately $401 million (excluding $49 million realized net gains on canceled contracts), $308 million, $230 million (excluding $27 million realized gains on canceled contracts), $56 million and $55 million for the years ended December 31, 2009, 2010 and 2011 and the three months ended March 31, 2011 and 2012, respectively.
(2)General and administrative expenses for the years ended December 31, 2009, 2010 and 2011 and the three months ended March 31, 2011 and 2012 include approximately $15 million, $13 million, $21 million, $5 million and $8 million of noncash unit-based compensation expenses, respectively. General and administrative expenses excluding these amounts were $0.90 per Mcfe, $0.88 per Mcfe, $0.83 per Mcfe, $0.90 per Mcfe and $0.83 per Mcfe for the years ended December 31, 2009, 2010 and 2011 and the three months ended March 31, 2011 and 2012, respectively. This is a non-GAAP measure used by LINN’s management to analyze its performance.

Index to Financial Statements
(3)In accordance with SEC regulations, reserves at December 31, 2009, 2010 and 2011 were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The price used to estimate reserves is held constant over the life of the reserves.
(4)Based on annualized average daily production from continuing operations for the fourth quarter of each respective year.
(5)Standardized measure of discounted future net cash flows is the present value of estimated future net revenues to be generated from the production of proved reserves, discounted using an annual discount rate of 10% and determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses or depreciation, depletion and amortization. Standardized measure of discounted future net cash flows does not give effect to derivative transactions. However, LINN estimates the discounted present value, or PV-10, of its approximately 3.4 Tcfe of proved reserves at December 31, 2011, to be approximately $7.1 billion, based on oil and natural gas hedge values for 2012-2016 and strip prices as of December 31, 2011. This calculation of PV-10 differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is presented including the impacts of commodity derivatives and current strip prices, rather than market prices and without giving effect to derivatives. LINN calculates PV-10 in this manner because a large percentage of its forecasted oil and natural gas production is hedged for multiple-year periods, and management therefore believes that LINN’s PV-10 calculation more accurately reflects the discounted present value of its estimated future net revenues. The information used to calculate PV-10 is not derived directly from data determined in accordance with authoritative accounting guidance regarding disclosure about oil and natural gas producing activities. LINN’s calculation of PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC. For a reconciliation of PV-10 to the standardized measure of discounted future net cash flows see “—PV-10.”

Index to Financial Statements

Non-GAAP Financial Measures

LINN defines adjusted EBITDA as net income (loss) plus the following adjustments:

Net operating cash flow from acquisitions and divestitures, effective date through closing date;

Interest expense;

Depreciation, depletion and amortization;

Impairment of long-lived assets;

Write-off of deferred financing fees;

(Gains) losses on sale of assets and other, net;

Provision for legal matters;

Loss on extinguishment of debt;

Unrealized (gains) losses on commodity derivatives;

Unrealized (gains) losses on interest rate derivatives;

Realized (gains) losses on interest rate derivatives;

Realized (gains) losses on canceled derivatives;

Unit-based compensation expenses;

Exploration costs; 

Income tax (benefit) expense; and

Discontinued operations.

Adjusted EBITDA is a measure used by LINN’s management to indicate (prior to the establishment of any reserves by the board of directors) the cash distributions LINN expects to make to its unitholders. Adjusted EBITDA is also a quantitative measure used throughout the investment community with respect to publicly traded partnerships and limited liability companies.

Index to Financial Statements

The following table presents a reconciliation of net income (loss) to adjusted EBITDA (unaudited):

  Year Ended December 31,  Three Months Ended March 31, 
      2009          2010          2011              2011              2012         
  (in thousands) 

Net income (loss)

 $(298,192 $(114,288 $438,439   $(446,682 $(6,202

Plus:

     

Net operating cash flow from acquisitions and divestitures, effective date through closing date

  3,708    42,846    57,966    7,051    39,093  

Interest expense, cash

  74,185    129,691    249,085    63,590    42,879  

Interest expense, noncash

  18,516    63,819    10,640    (126  34,640  

Depreciation, depletion and amortization

  201,782    238,532    334,084    66,366    117,276  

Impairment of long-lived assets

  —      38,600    —      —      —    

Write-off of deferred financing fees

  204    2,076    1,189    —      1,660  

(Gains) losses on sale of assets and other, net

  (23,051  3,008    124    (823  1,435  

Provision for legal matters

  —      4,362    1,086    492    635  

Loss on extinguishment of debt

  —      —      94,612    84,562    —    

Unrealized (gains) losses on commodity derivatives

  591,379    232,376    (192,951  425,285    53,224  

Unrealized (gains) losses on interest rate derivatives

  (16,588  (63,978  —      —      —    

Realized losses on interest rate derivatives

  42,881    8,021    —      —      —    

Realized (gains) losses on canceled derivatives

  (48,977  123,865    (26,752  —      —    

Unit-based compensation expenses

  15,089    13,792    22,243    5,638    8,171  

Exploration costs

  7,169    5,168    2,390    445    410  

Income tax (benefit) expense

  (4,221  4,241    5,466    4,198    8,918  

Discontinued operations

  2,351    —      —      —      —    
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted EBITDA

 $566,235   $732,131   $997,621   $209,996   $302,139  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Index to Financial Statements

PV-10

PV-10 represents the present value, discounted at 10% per year, of estimated future net revenues. LINN’s calculation of PV-10 differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is presented including the impacts of its oil and natural gas hedge values for 2012-2016 and strip prices as of December 31, 2011, rather than the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, and without giving effect to derivatives. LINN calculates PV-10 value in this manner because such a large percentage of its forecasted oil and natural gas production is hedged for multiple-year periods, and management therefore believes that its PV-10 calculation more accurately reflects the value of its estimated future net revenues. The information used to calculate PV-10 is not derived directly from data determined in accordance with the provisions of applicable accounting standards. LINN’s calculation ofCompany. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rulesas computed under GAAP.



Summary Historical Reserve and regulations of the SEC. Operating Data

The following table presents, as of December 31, 2018, summary data with respect to our estimated net proved reserves.

The reserve estimates attributable to our properties as of December 31, 2018 are based on a reconciliationreserve report prepared by DeGolyer and MacNaughton, using SEC pricing. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Oil and Natural Gas Data—Proved Reserves” in evaluating the material presented below.

   As of December 31, 2018 (1) 

Proved developed reserves:

  

Oil (MBbls)

   18,652 

Natural gas (MMcf)

   369,677 

NGLs (MBbls)

   39,927 
  

 

 

 

Total (MBoe)(2)

   120,192 

Proved undeveloped reserves:

  

Oil (MBbls)

   37,031 

Natural gas (MMcf)

   541,505 

NGLs (MBbls)

   58,485 
  

 

 

 

Total (MBoe)(2)

   185,767 

Total proved reserves:

  

Oil (MBbls)

   55,683 

Natural gas (MMcf)

   911,182 

NGLs (MBbls)

   98,412 
  

 

 

 

Total (MBoe)(2)

   305,959 
  

 

 

 

Benchmark Oil and Natural Gas Prices(1):

  

Oil—WTI per Bbl

  $65.66 

Natural gas—Henry Hub per MMBtu

  $3.16 

Standardized measure (in thousands)

  $1,699,701 

PV-10 of proved reserves
(in thousands)(3)

  $2,091,509 

(1)

Our estimated net proved reserves were determined using averagefirst-day-of-the-month prices for the prior 12 months in accordance with SEC guidance adjusted for quality, transportation fees, regional price differentials, and in the case of natural gas, energy content. For oil and NGLs volumes, the average WTI posted price of $65.66 per barrel as of December 31, 2018, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $3.16 per MMBtu as of December 31, 2018 was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.49 per barrel of oil, $20.35 per barrel of NGLs and $1.90 per Mcf of natural gas as of December 31, 2018.

(2)

Totals may not sum or recalculate due to rounding.

(3)

PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. NeitherPV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry usePV-10 as a measure to compare the relative size and value of proved reserves held by



companies without regard to the specific tax characteristics of such entities. Please see “Summary Historical and Unaudited Pro Forma FinancialData—Non-GAAP FinancialMeasure—PV-10.”

The following table reconciles the GAAP standardized measure of discounted future net cash flows to LINN’s calculation of PV-10 at December 31, 20112018 (in millions)thousands):

 

Standardized measure of discounted future net cash flows

  $6,615  

Plus: Difference due to oil and natural gas hedge prices and strip prices for unhedged volumes

   450  
  

 

 

 

PV-10

  $7,065  
  

 

 

 

Standardized measure of discounted future net cash flows

  $1,699,701 

Present value of future income taxes discounted at 10%

   391,808 
  

 

 

 

PV-10 of proved reserves

  $2,091,509 
  

 

 

 

The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

Index to Financial Statements

   Three Months Ended
March 31,
   Year Ended
December 31,
2018
   Year Ended
December 31,
2017
 
   2019  2018 

Production data:

       

Oil (MBbls)

   1,139   1,038    4,364    1,454 

Natural gas (MMcf)

   11,620   8,912    41,890    17,582 

NGLs (MBbls)

   1,329   874    4,592    1,524 

Total (MBoe)(1)

   4,405   3,397    15,938    5,908 

Average daily production (MBoe/d)

   48.9   37.7    43.7    16.2 

Average prices(2):

       

Oil (per Bbl)

  $53.18  $61.36   $63.07   $52.87 

Natural gas (per Mcf)

  $1.87  $1.90   $1.82   $2.80 

NGLs (per Bbl)

  $12.18  $23.33   $19.27   $26.44 

Total (per Boe)

  $22.37  $29.72   $27.59   $28.16 

Average realized prices after effects of derivative settlements(2)(3):

       

Oil (per Bbl)

  $59.46  $56.78   $55.87   $53.57 

Natural gas (per Mcf)

  $1.53  $1.92   $1.73   $2.89 

NGLs (per Bbl)

  $13.86  $23.33   $19.60   $26.44 

Total (per Boe)

  $23.59  $28.39   $25.50   $28.60 

Average costs (per MBoe)(2):

       

Production expenses

  $3.37  $2.46   $2.99   $2.86 

Gathering, transportation and processing expenses

  $—    $—     $—     $3.15 

Production taxes

  $1.14  $0.70   $1.10   $0.62 

Exploration expenses

  $2.84  $2.31   $2.72   $5.52 

Depreciation, depletion, amortization and accretion

  $9.44  $6.44   $7.78   $6.33 

General and administrative

  $3.59  $4.13   $3.82   $5.31 

Gain on sale of assets

  $(0.15 $—     $—     $(0.14
  

 

 

  

 

 

   

 

 

   

 

 

 

Total

  $20.23  $16.04   $18.41   $23.65 
  

 

 

  

 

 

   

 

 

   

 

 

 

(1)

May not sum or recalculate due to rounding.

(2)

Average prices and costs for the three months ended March 31, 2019 and 2018 and the year ended December 31, 2018 reflect the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering,



processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
(3)

Excludes settlements of commodity derivative contracts prior to their contractual maturity.



RISK FACTORS

An investmentInvesting in our sharesClass A common stock involves risks. You should carefully consider the following risk factors together with all of the other information included in this prospectus, in evaluatingincluding the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment in our shares.decision. If certainany of the following risks wereactually occur, the trading price of our Class A common stock could decline and you may lose all or part of your investment. Additional risks not presently known to occur, LINN’sus or that we currently deem immaterial could also materially affect our business.

Risks Related to Our Business

Oil, natural gas and NGL prices are volatile. A decline in commodity prices may adversely affect our business, financial condition or results of operations and ours, as a result, could be materially adversely affected. In that case, LINN might not be able to pay any distribution on its units, the trading price of our shares could decline and you could lose all or part of your investment in us. In addition, if certain of the following risks were to occur, our financial condition or the price of our shares could be materially adversely affected.

Risks Related to LINN’s Business

LINN actively seeks to acquire oil and natural gas properties. Acquisitions involve potential risks that could adversely impact its future growth and its ability to increase or pay distributions at the current level, or at all.meet our capital expenditure obligations and financial commitments.

Any acquisition involves potential risks, including, among other things:

the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

the risk of title defects discovered after closing;

inaccurate assumptions about revenues and costs, including synergies;

significant increases in LINN’s indebtedness and working capital requirements;

an inability to transition and integrate successfully or timely the businesses LINN acquires;

the cost of transition and integration of data systems and processes;

the potential environmental problems and costs;

the assumption of unknown liabilities;

limitations on rights to indemnity from the seller;

the diversion of management’s attention from other business concerns;

increased demands on existing personnel and on the corporate structure;

disputes arising out of acquisitions;

customer or key employee losses of the acquired businesses; and

the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, LINN’s future acquisition costs may be higher than those it has achieved historically. Any of these factors could adversely impact its future growth and its ability to increase or pay distributions.

If LINN does not make future acquisitions on economically acceptable terms, then its growth and ability to increase distributions will be limited.

LINN’s ability to grow and to increase distributions to its unitholders is partially dependent on its ability to make acquisitions that result in an increase in available cash flow per unit. It may be unable to make such acquisitions because it is:

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

unable to obtain financing for these acquisitions on economically acceptable terms; or

outbid by competitors.

Index to Financial Statements

In any such case, LINN’s future growth and ability to increase distributions will be limited. Furthermore, even if LINN does make acquisitions that it believes will increase available cash flow per unit, these acquisitions may nevertheless result in a decrease in available cash flow per unit.

LINN has significant indebtedness under its Senior Notes and from time to time, its Credit Facility. The Credit Facility and the indentures governing the Senior Notes have substantial restrictions and LINN may have difficulty obtaining additional credit, which could adversely affect its operations, its ability to make acquisitions and its ability to pay distributions to its unitholders, including us.

As of March 31, 2012, LINN had an aggregate of approximately $5.0 billion in outstanding senior notes (“Senior Notes”) and borrowings under its Fifth Amended and Restated Credit Agreement (“Credit Facility”) with additional borrowing capacity of approximately $1.9 billion under its Credit Facility, which includes a $4 million reduction in availability for outstanding letters of credit. As a result of its indebtedness, LINN will use a portion of its cash flow to pay interest and principal when due, which will reduce the cash available to finance its operations and other business activities and could limit its flexibility in planning for or reacting to changes in its business and the industry in which it operates.

The Credit Facility restricts LINN’s ability to obtain additional financing, make investments, lease equipment, sell assets, enter into commodity and interest rate derivative contracts and engage in business combinations. LINN is also required to comply with certain financial covenants and ratios under its Credit Facility. Its ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from its operations and events or circumstances beyond its control. LINN’s failure to comply with any of the restrictions and covenants could result in an event of default, which, if it continues beyond any applicable cure periods, could cause all of its existing indebtedness to be immediately due and payable.

LINN depends, in part, on its Credit Facilityprices we receive for future capital needs. LINN has drawn on its Credit Facility to fund or partially fund quarterly cash distribution payments, since it uses operating cash flow primarily for drilling and development of oil and natural gas properties and acquisitions and borrows as cash is needed. Absent such borrowing, it would have at times experienced a shortfall in cash available to pay its declared quarterly cash distribution amount. If there is a default by LINN under its Credit Facility that continues beyond any applicable cure period, it would be unable to make borrowings to fund distributions. In addition, LINN may finance acquisitions through borrowings under its Credit Facility or the incurrence of additional debt. To the extent that LINN is unable to incur additional debt under its Credit Facility or otherwise because it is not in compliance with the financial covenants in the Credit Facility, it may not be able to complete acquisitions, which could adversely affect its ability to maintain or increase distributions. Furthermore, to the extent LINN is unable to refinance its Credit Facility on terms that are as favorable as those in its existing Credit Facility, or at all, its ability to fund its operations and its ability to pay distributions could be affected.

The borrowing base under LINN’s Credit Facility is determined semi-annually at the discretion of the lenders and is based in part onour oil, natural gas and NGL prices. Significant declines in oil, natural gas or NGL prices may result in a decrease in its borrowing base. The lenders can unilaterally adjust the borrowing base and therefore the borrowings permitted to be outstanding under the Credit Facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or LINN must pledge other properties as additional collateral. LINN does not currently have substantial unpledged properties, and it may not have the financial resources in the future to make any mandatory principal prepayments required under the Credit Facility. Significant declines in LINN’s production or significant declines in realized oil, natural gas or NGL prices for prolonged periods and resulting decreases in its borrowing base may force it to reduce or suspend distributions to its unitholders.

Index to Financial Statements

LINN’s ability to access the capital and credit markets to raise capital and borrow on favorable terms will be affected by disruptions in the capital and credit markets, which could adversely affect its operations, its ability to make acquisitions and its ability to pay distributions to its unitholders.

Disruptions in the capital and credit markets could limit LINN’s ability to access these markets or significantly increase its cost to borrow. Some lenders may increase interest rates, enact tighter lending standards, refuse to refinance existing debt at maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. If LINN is unable to access the capital and credit markets on favorable terms, its ability to make acquisitions and pay distributions could be affected.

LINN’s variable rate indebtedness subjects it to interest rate risk, which could cause its debt service obligations to increase significantly.

Borrowings under LINN’s Credit Facility bear interest at variable rates and expose LINN to interest rate risk. If interest rates increase and LINN is unable to effectively hedge its interest rate risk, its debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and its net income and cash available for servicing its indebtedness would decrease.

Increases in interest rates could adversely affect the demand for LINN’s units.

An increase in interest rates may cause a corresponding decline in demand for equity investments, in particular for yield-based equity investments such as LINN units. Any such reduction in demand for LINN units resulting from other more attractive investment opportunities may cause the trading price of LINN units to decline.

LINN’s commodity derivative activities could result in financial losses or could reduce its income, which may adversely affect its ability to pay distributions to its unitholders.

To achieve more predictable cash flow and to reduce its exposure to adverse fluctuations in the prices of oil and natural gas, LINN enters into commodity derivative contracts for a significant portion of its production. Commodity derivative arrangements expose it to the risk of financial loss in some circumstances, including situations when production is less than expected. If LINN experiences a sustained material interruption in its production or if it is unable to perform its drilling activity as planned, it might be forced to satisfy all or a portion of its derivative obligations without the benefit of the cash flow from its sale of the underlying physical commodity, resulting in a substantial reduction of its liquidity, which may adversely affect its ability to pay distributions to its unitholders.

Counterparty failure may adversely affect LINN’s derivative positions.

LINN cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, LINN’s cash flow and ability to pay distributions could be impacted.

Commodity prices are volatile, and a significant decline in commodity prices for a prolonged period would reduce LINN’s revenues, cash flow from operations and profitability and it may have to lower its distribution or may not be able to pay distributions at all, which would in turn reduce or eliminateheavily influence our ability to pay dividends to you.

LINN’s revenue, profitability, access to capital, future rate of growth and cash flow depend upon the pricescarrying value of and demand for oil,our properties. Oil, natural gas and NGL. The oil, natural gasNGLs are commodities, and NGL market is very volatile and a drop intheir prices can significantly affect LINN’s financial results and impede its growth. Changes in oil, natural gas and NGL prices have a significant impact on the value of LINN’s reserves and on its cash flow. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for them, market uncertainty and a variety of additional factors that are beyond LINN’s control, such as:

the domestic and foreign supply of and demand for oil, natural gas and NGL;

NGLs. Historically, oil, natural gas and NGL prices have been volatile and will likely continue to be volatile in the future. Beginning in the second half of 2014, oil and natural gas prices began a rapid and significant decline as global supply exceeded demand. This oversupply continued through the first half of 2016 and led to troughs in oil and natural gas prices, which at their lowest New York Mercantile Exchange (“NYMEX”) prices were $27.45 per Bbl and $1.64 per MMBtu, respectively. Although average oil and gas prices increased in the first nine months of 2018, reaching levels as high as $76.41 per Bbl and $4.84 per MMBtu, respectively, they began to decline again in the fourth quarter of 2018 and in early 2019, reaching levels as low as $61.59 per Bbl and $2.46 per MMBtu during April 2019. Likewise, NGLs, which are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics suffered significant declines in realized prices but also began to recover in the second half of 2017 and during the year ended December 31, 2018, reaching levels as high as $10.46 per MMBtu. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control that include, but are not limited to, the following:

Index to Financial Statements

worldwide and regional political or economic conditions impacting the priceglobal supply and level of foreign imports;demand for oil, natural gas and NGLs;

 

the level of consumer product demand;global oil, natural gas and NGL exploration and production;

 

weather conditions;

overall domestic and global economic conditions;the level of commodity storage inventories;

 

political and economic conditions in oil and natural gasor affecting other producing regions or countries, including those in the Middle East, Africa, South America and South America;Russia;

 

the ability of membersactions of the Organization of the Petroleum Exporting Countries, its members and other state-controlled oil companies relating to agree to and maintainoil price and production controls;

 

prevailing prices on local price indexes in the impactarea in which we operate and expectations about future commodity prices;

the proximity, capacity, cost and availability of gathering and transportation facilities;

localized and global supply and demand fundamentals and transportation availability;

the U.S. dollar exchange rates on oil,cost of exploring for, developing and producing reserves and transporting production;

weather conditions and other natural gas and NGL prices;disasters;

 

technological advances affecting energy consumption;consumption and production;

domesticspeculative trading in oil, natural gas and foreign governmental regulations and taxation;

the impact of energy conservation efforts;

the proximity and capacity of pipelines and other transportation facilities; andNGL markets;

 

the price and availability of alternative fuels.

In the past, the prices of oil, natural gas and NGL have been extremely volatile, and LINN expects this volatility to continue. If commodity prices decline significantly for a prolonged period, LINN’s cash flow from operations will decline, and it may have to lower its distribution or may not be able to pay distributions at all, which would in turn reduce or eliminate our ability to pay dividends to you.

Future price declines or downward reserve revisions may result in a write down of LINN’s asset carrying values, which could adversely affect its results of operations and limit its ability to borrow funds.

Declines in oil, natural gas and NGL prices may result in LINN having to make substantial downward adjustments to its estimated proved reserves. If this occurs, or if LINN’s estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require it to write down, as a noncash charge to earnings, the carrying value of its properties for impairments. LINN capitalizes costs to acquire, find and develop its oil and natural gas properties under the successful efforts accounting method. LINN is required to perform impairment tests on its assets periodically and whenever events or changes in circumstances warrant a review of its assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of LINN’s assets, the carrying value may not be recoverable and therefore would require a write down. LINN may incur impairment charges in the future, which could have a material adverse effect on its results of operations in the period incurred and on its ability to borrow funds under its Credit Facility, which in turn may adversely affect its ability to make cash distributions to its unitholders.

Unless LINN replaces its reserves, its reserves and production will decline, which would adversely affect its cash flow from operations and its ability to make distributions to its unitholders.

Producing oil, natural gas and NGL reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The overall rate of decline for LINN’s production will change if production from its existing wells declines in a different manner than its has estimated and can change when it drills additional wells, makes acquisitions and under other circumstances. Thus, LINN’s future oil, natural gas and NGL reserves and production and, therefore, its cash flow and income, are highly dependent on its success in efficiently developing its current reserves and economically finding or acquiring additional recoverable reserves. LINN may not be able to develop, find or acquire additional reserves to replace its current and future production at acceptable costs, which would adversely affect its cash flow from operations and its ability to make distributions to its unitholders.

Index to Financial Statements

LINN’s estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of LINN’s reserves.

No one can measure underground accumulations of oil, natural gas and NGL in an exact manner. Reserve engineering requires subjective estimates of underground accumulations of oil, natural gas and NGL and assumptions concerning future oil, natural gas and NGL prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Independent petroleum engineering firms prepare estimates of our proved reserves. Some of LINN’s reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, LINN makes certain assumptions regarding future oil, natural gas and NGL prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual amounts could greatly affect LINN’s estimates of reserves, the economically recoverable quantities of oil, natural gas and NGL attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which LINN’s reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGL LINN ultimately recovers being different from its reserve estimates.

The present value of future net cash flows from LINN’s proved reserves is not necessarily the same as the current market value of its estimated oil, natural gas and NGL reserves. LINN bases the estimated discounted future net cash flows from its proved reserves on an unweighted average of the first-day-of-the-month price for each month during the 12-month calendar year and year-end costs. However, actual future net cash flows from its oil and natural gas properties also will be affected by factors such as:

actual prices we receive for oil, natural gas and NGL;

the amount and timing of actual production;

the timing and success of development activities;

supply of and demand for oil, natural gas and NGL;fuels; and

 

changes inU.S. federal, state and local andnon-U.S. governmental regulations or taxation.regulation and taxes.

In addition, the 10% discount factor required to be used under the provisions of applicable accounting standards when calculating discounted future netLower commodity prices may reduce our cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with LINN or the oil and natural gas industry in general.

LINN’s development operations require substantial capital expenditures, which will reduce its cash available for distribution. LINN may beborrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop our reserves could be adversely affected. Furthermore, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI or Henry Hub prices may adversely affect our drilling economics and our ability to raise capital, which may require us tore-evaluate and postpone or eliminate our development drilling, and result in the reduction of some of our proved undeveloped reserves and the net present value of our reserves. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a further reduction or sustained decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

Our business requires substantial capital expenditures. We may be unable to generate sufficient cash from operations or obtain required capital or financing as needed or on acceptable terms, which could lead to a decline in itsour ability to access or grow production and reserves.

The oil and natural gas industry is capital intensive. LINN makescapital-intensive. We currently make, and expectsexpect to continue to makemaking, substantial capital expenditures. We expect to fund our 2019 capital expenditures in its businesswith cash generated by operations, borrowings under our credit facility and access to capital markets; however, our financing needs may require us to alter or increase our capitalization substantially through the incurrence of additional indebtedness or the issuance of debt or equity securities or the sale of assets. The incurrence of additional indebtedness would require that a portion of our cash flow from operations be used for the developmentpayment of interest and productionprincipal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL reserves. These expenditures will reduce LINN’s cash available for distribution. LINN intends to finance its futureprices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, with cash flow from operations and,which would negatively impact our ability to the extent necessary, with equity and debt offerings or bank borrowings. LINN’sgrow production.

Our cash flow from operations and access to capital are subject to a number of variables including:that include, but are not limited to, the following:

 

itsthe prices at which our production is sold;

our proved reserves;

 

the levelvolume and types of oil, natural gas and NGL it ishydrocarbons we are able to produce from existing wells;

 

the prices at which it is able to sell its oil, natural gas and NGL; and

itsour ability to acquire, locate and produce new reserves.reserves;

our ability to Financial Statementsborrow under our credit facility and our ability to access the capital markets.

If LINN’sour revenues or the borrowing base under its Credit Facilityour credit facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, itwe may have limited ability to obtain the capital necessary to sustain itsour operations at current levels. LINN’s Credit Facility restricts its ability to obtain new financing. If additional capital is needed, itwe may not be able to obtain debt or equity financing on terms favorableacceptable to it, orus, if at all. If cash flow fromgenerated by our operations or cash available borrowings under the Credit Facility isour credit facility are not sufficient to meet LINN’sour capital requirements, the failure to obtain additional financing could result in a curtailment of itsour operations relating to development operations,of our properties, which in turn could lead to a possible decline in its reserves.our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.

LINNWe have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.

Our assets were contributed to Roan LLC in August 2017 by Old Linn and Citizen. Under management services agreements (“MSAs”), Old Linn and Citizen operated the contributed oil and natural gas assets on our behalf until May 2018, at which time our management team took over as operator of the contributed oil and natural gas properties. As a result, there is only limited historical financial and operational information available upon which to base your evaluation of our performance.

In addition, we have grown rapidly over the last year. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

increased responsibilities for our executive level personnel;

increased administrative burden;

increased capital requirements; and

increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may decidebe realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

Restrictions in our credit facility could limit our growth and our ability to drillengage in certain activities.

Our credit facility contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

incur additional indebtedness;

incur liens;

enter into mergers;

sell assets;

make investments and loans;

make or declare dividends;

enter into commodity hedges exceeding a specified percentage of our expected production or proved reserves;

enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness; and

engage in transactions with affiliates.

In addition, our credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios.

The restrictions in our credit facility may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our credit facility impose on us.

A breach of any covenant in our credit facility would result in a default under such facility after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding

under our credit facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness on acceptable terms, if at all.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, as of March 31, 2019, we had $602.6 million of debt outstanding, with a weighted average interest rate of 5.25%, and a 1.0% increase in interest rates would result in an increase in annual interest expense of $6.0 million, assuming no change in the amount of debt outstanding. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Any significant reduction in our borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, will determine semiannually on April 1st and October 1st of each year. The borrowing base will depend on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties securing our credit facility and hedging arrangements. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. Any increase in the borrowing base will require the consent of the lenders holding 100% of the commitments.

In the future, we may not be able to access adequate funding under our credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations if other lenders are unable to provide additional funding to cover any defaulting lender’s position. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our credit facility, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business

operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the prospects it has identified,absence of sufficient cash flows and locations that it decidescapital resources, we could face substantial liquidity problems and might be required to drilldispose of material assets or operations to meet debt service and other obligations. We may not yieldbe able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and NGL in commercially viable quantities.operating expenses, capital expenditures, taxes and availability of funds.

LINN’s prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, includingActual future production, oil, natural gas and NGL prices, the generationrevenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional seismic or geological information, the availabilityproduction history, results of drilling rigsdevelopment activities, current commodity prices and other factors, LINNexisting factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may decidediffer materially from those used in the present value estimate. Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.

The standardized measure of our estimated reserves contained in this prospectus and in the footnotes to our financial statements is not an accurate estimate of the current fair value of our estimated reserves.

Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC, as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of our estimated reserves included in this prospectus should not be construed as accurate estimates of the current fair value of our proved reserves.

The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.

As of December 31, 2018, approximately 61% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill oneand develop such reserves or moredecreases in commodity prices will reduce the value of these prospects. As aour estimated PUDs and future net revenues estimated for such reserves and may result LINNin some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to lose leases through expiration or could cause us to reclassify our PUDs as unproved reserves. Further, we may be required to write down our PUDs if we do not drill those wells within five years after their respective dates of booking.

Our future cash flows and results of operations are highly dependent on our ability to find, develop or acquire additional reserves.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to increasedevelop, find or maintain itsacquire sufficient additional reserves orto replace our current and future production. If we are unable to replace our current and future production, which in turn could have an adverse effect on itsthe value of our reserves will decrease, and our business, financial position,condition and results of operations and its ability to pay distributions. In addition, the SEC’s reserve reporting rules include a general requirement that, subject to limited exceptions, proved undeveloped reserves may onlywould be booked if they relate to wells scheduled to be drilled within five years of the date of booking. At December 31, 2011, LINN had 2,302 proved undeveloped drilling locations. To the extent that LINN does not drill these locations within five years of initial booking, they may not continue to qualify for classification as proved reserves, and LINN may be required to reclassify such reserves as unproved reserves. The reclassification of such reserves could also have a negative effect on the borrowing base under the Credit Facility.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. LINN’s efforts will be uneconomic if it drills dry holes or wells that are productive but do not produce enough oil, natural gas and NGL to be commercially viable after drilling, operating and other costs. If LINN drills future wells that it identifies as dry holes, its drilling success rate would decline, which could have an adverse effect on its business, financial position or results of operations.

LINN’s business depends on gathering and transportation facilities. Any limitation in the availability of those facilities would interfere with its ability to market the oil, natural gas and NGL it produces, and could reduce its cash available for distributionmaterially and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.affected.

The marketability of LINN’s oil, natural gas and NGL production depends in part on the availability, proximity and capacity of gathering and pipeline systems. The amount of oil, natural gas and NGL that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, LINN is provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of its wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, LINN may not be able to sell the oil, natural gas and NGL production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would interfere with LINN’s ability to market the oil, natural gas and NGL it produces, and could reduce its cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from its drilling program.

Index to Financial Statements

LINN depends on certain key customers for sales of our oil, natural gas and NGL. To the extent these and other customers reduce the volumes they purchase from LINN or delay payment, LINN’s revenues and cash available for distribution could decline. Further, a general increase in nonpayment could have an adverse impact on its financial position and results of operations.

For the year ended December 31, 2011, Enbridge Energy Partners, L.P. and DCP Midstream Partners, LP accounted for approximately 21% and 19%, respectively, of LINN’s total production volumes, or 40% in the aggregate. For the year ended December 31, 2010, DCP Midstream Partners, LP, Enbridge Energy Partners, L.P. and ConocoPhillips accounted for approximately 19%, 17% and 12%, respectively, of LINN’s total volumes, or 48% in the aggregate. To the extent these and other customers reduce the volumes of oil, natural gas or NGL that they purchase from LINN, its revenues and cash available for distribution could decline.

Many of LINN’s leases are in areas that have been partially depleted or drained by offset wells.

LINN’s key project areas are located in some of the most active drilling areas of the producing basins in the U.S. As a result, many of its leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit its ability to find economically recoverable quantities of reserves in these areas.

LINN’s identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact LINN’s ability to pay distributions.

LINN’s management has specifically identified and scheduled drilling locations as an estimation of LINN’s future multi-year drilling activities on its existing acreage. As of December 31, 2011, LINN had identified 6,456 drilling locations, of which 2,302 were proved undeveloped locations and 4,154 were other locations. These identified drilling locations represent a significant part of LINN’s growth strategy. Its ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGL prices, costs and drilling results. In addition, DeGolyer and MacNaughton has not estimated proved reserves for the 4,154 other drilling locations LINN has identified and scheduled for drilling, and therefore there may be greater uncertainty with respect to the success of drilling wells at these drilling locations. LINN’s final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of its drilling activities with respect to its proved drilling locations. Because of these uncertainties, LINN does not know if the numerous drilling locations it has identified will be drilled within its expected timeframe or will ever be drilled or if it will be able to produce oil, natural gas and NGL from these or any other potential drilling locations. As such, LINN’s actual drilling activities may materially differ from those presently identified, which could adversely affect its business.

Drilling for and producing oil and natural gas and NGL are high risk activities with many uncertainties that could adversely affect LINN’sour business, financial positioncondition or results of operations.

Our future financial condition and results of operations will depend on the success of our development, acquisition and as a result, its ability to pay distributions to its unitholders.

LINN’s drillingproduction activities, which are subject to manynumerous risks beyond our control, including the risk that itdrilling will not discoverresult in commercially productive reservoirs. Drilling forviable oil and natural gas production.

Our decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical and NGL can be uneconomic, not only from dry holes, but also from productive wellsgeological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, please see “—Reserve estimates depend on many assumptions that do not produce sufficient revenuesmay turn out to be commercially viable.inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, LINN’sour cost of drilling, completing and producing operationsoperating wells is often uncertain.

Further, many factors may be curtailed, delayedcurtail, delay or canceled as a result of other factors, including:cancel our scheduled drilling projects, which include, but are not limited to, the following:

 

the high cost, shortages or delivery delayscompliance with regulatory requirements, including those relating to water supply, discharge and disposal of equipmentwaste water and services;other hazardous materials, emission of greenhouse gases (“GHGs”) and limitations on hydraulic fracturing;

 

pressure or irregularities in geological formations;

shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

equipment failures, accidents or other unexpected operational events;incidents;

lack of available gathering facilities or delays in construction of gathering facilities;

lack of available capacity on interconnecting transmission pipelines;

 

adverse weather conditions;

 

facilityenvironmental hazards, such as oil and natural gas leaks, oil spills, fires or equipment malfunctions;

Index to Financial Statements

title problems;explosions, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

 

pipeline ruptures or spills;declines in oil and natural gas prices;

 

compliance with environmental and other governmental requirements;limited availability of financing at acceptable terms;

 

unusual or unexpected geological formations;

loss of drilling fluid circulation;

formations with abnormal pressures;

fires;

blowouts, craterings and explosions;title problems; and

 

uncontrollable flows oflimitations in the market for oil and natural gas and NGL or well fluids.gas.

AnyCertain of these eventsrisks can cause increased costs or restrict LINN’s ability to drill the wells and conduct the operations which it currently has planned. Any delay in the drilling program or significant increase in costs could impact LINN’s ability to generate sufficient cash flow to pay quarterly distributions to its unitholders at the current distribution level or at all. Increased costs could includesubstantial losses, fromincluding personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory fines or penalties. LINN ordinarily maintains

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take impairment write-downs of the carrying values of our properties.

Accounting rules require that our proved oil and natural gas properties should be tested for recoverability whenever events or circumstances indicate that the carrying amount may not be recoverable. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment tests, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes anon-cash charge to earnings. We did not incur impairment charges of proved properties during the year ended December 31, 2018 or the three months ended March 31, 2019.

Our derivative activities could result in financial losses or could reduce our earnings.

We enter into derivative instrument contracts for a portion of our oil and natural gas production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of any derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

production is less than the volume covered by the derivative instruments;

the counterparty to the derivative instrument defaults on its contractual obligations;

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

there are issues with regard to legal enforceability of such instruments.

If we enter into derivative instruments that require cash collateral, our cash otherwise available for use in our operations would be reduced. Any future collateral requirements will depend on financial and industry market conditions and arrangements with our counterparties. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition. Alternatively, higher oil and natural gas prices may result in significantnon-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses

associated with those hedging contracts when oil and natural gas prices rise. Additionally, in times of low commodity prices, our ability to enter into additional commodity derivative contracts with favorable commodity price terms may be limited, which may adversely impact our future revenues and cash flows as compared to historical periods during which we were able to hedge our oil and natural gas production at higher prices.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, our derivative contract asset positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

The enactment of derivatives legislation and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to reduce the effect of risks associated with our business.

The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the OTC derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the Commodity Futures Trading Commission (“CFTC”) to promulgate a range of rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may enter or the ability and willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.

In addition, the European Union and othernon-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations. At this time, the impact of such regulations is not clear.

We have an extensive inventory of future potential drilling locations that could be developed over an extended period of time, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to generate sufficient cash from operations or raise the substantial amount of capital that may be necessary to drill such locations.

Subject to our management determining an appropriate number of wells to drill per section from a spacing perspective, we expect to identify a large number of future drilling locations on our existing acreage. These drilling locations will represent a significant part of our growth strategy. Our ability to drill and develop these locations will depend on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, access to suitable surface drilling pad locations, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the drilling locations our management team identifies will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other drilling locations.

In addition, we may require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital or financing required to

do so. Please see “—Our business requires substantial capital expenditures. We may be unable to generate sufficient cash from operations or obtain required capital or financing as needed or on acceptable terms, which could lead to a decline in our ability to access or grow production and reserves.”

Approximately 16% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

As of December 31, 2018, approximately 16% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage. Further, to the extent we determine that it is not economic to develop particular undeveloped acreage, we may intentionally allow leases to expire.

We may incur losses as a result of title defects in the properties in which we invest.

It is generally our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the leases and underlying mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

landing our wellbore in the desired drilling zone;

staying in the desired drilling zone while drilling horizontally through the formation;

running our casing the entire length of the wellbore; and

being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to, the following:

the ability to fracture stimulate the planned number of stages;

the ability to run tools the entire length of the wellbore during completion operations; and

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of any drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established

production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Multi-well pad drilling may result in volatility in our operating results.

We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our quarterly operating results.

We will not be the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs or the rate of production of anynon-operated assets.

As of December 31, 2018, we had over 170,000 net acres in the Merge, STACK and SCOOP plays of the Anadarko Basin, approximately 71% of which we operated. As of December 31, 2018, we were the operator on 591 gross (449 net) of our 1,263 gross (502 net) producing wells. We will have limited ability to exercise influence over the operations of the drilling locations operated by our partners and there is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control that include, but are not limited to, the following:

the timing and amount of capital expenditures;

the operator’s expertise and financial resources;

the approval of other participants in drilling wells;

the selection of technology; and

the rate of production of reserves, if any.

This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activity.

Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporaryshut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in Oklahoma in past years. Although we have not been directly affected to date, these drought conditions have led governmental authorities in other areas of the state to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations, or if we experience delays in obtaining water sourcing permits or other rights, we may be unable to economically produce oil, natural gas and NGLs, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

Our producing properties are located in the Merge, STACK and SCOOP plays within the Anadarko Basin, in Oklahoma, making us vulnerable to risks associated with operating in a single geographic area.

All of our producing properties are geographically concentrated in the Merge, STACK and SCOOP plays within the Anadarko Basin in Central Oklahoma. At December 31, 2018, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we are disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought-related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

The marketability and pricing of our production is dependent upon transportation and other facilities and various market factors, which we generally do not control. If these facilities are unavailable or we become subject to adverse pricing differentials, our operations could be interrupted and our revenues reduced.

The marketability of our oil, natural gas and NGL production depends in part upon the availability, proximity and capacity of transportation and other production facilities owned by third parties. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to produce or deliver to market our oil, natural gas and NGLs, causing a significant interruption in our operations. While we believe we have reserved sufficient capacity with third-party facilities to gather, process, fractionate and transport a significant portion of our projected production, that capacity may not be sufficient to handle all of our production, or these third-party facilities may experience delays in construction, mechanical problems or become unavailable to us due to unforeseen circumstances.

Additionally, we depend on various trucking providers for our oil production and on two third-party midstream companies for substantially all of our current natural gas and NGL production. Our current natural gas and NGL arrangements provide for pricing at Mont Belvieu, Texas, but future arrangements could be tied to pricing at Conway, Kansas or other market hubs and subject us to adverse pricing differentials. In the future, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production, and such alternative arrangements may only be available on unfavorable terms, or not at all. If we are unable, for any sustained period, to access these third-party facilities or find acceptable alternative arrangements, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for gathering, processing, fractionating and delivering the oil, natural gas and NGLs produced from our fields, would materially and adversely affect our financial condition and results of operations.

We are subject to acreage dedications and one of our current midstream contracts contains a minimum volume commitment.

We are currently party to midstream contracts that contain acreage dedications through November 2030. We have multiple dedications within certain of our operated sections. As a result, we are required to manage our production to ensure these commitments are satisfied. If we are unable to effectively manage these split dedications within a section with multiple dedications, we would be in breach of one of the midstream contracts, which could have an adverse effect on our business and financial condition. For additional information regarding midstream contracts, see Note 14 to the audited financial statements included in this prospectus.

We may enter into firm transportation, gas processing, gathering and compression service, water handling and treatment, or other agreements that require minimum volume delivery commitments. We are currently party to a firm transportation agreement, which contains an aggregate minimum volume commitment of natural gas that is required to be delivered from a specific area by November 2021. Based on expected production from currently producing wells in the specified area, we anticipate that we may not deliver the required minimum volumes of natural gas by November 2021. As a result, we accrued $0.4 million for our share of the estimated

shortfall deficiency fees as of March 31, 2019. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to utilize our full firm transportation and processing capacity. If we have insufficient production to meet the minimum volumes under this agreement or any other firm commitment agreement we may enter into, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations.

Reliance upon a few large customers may adversely affect our revenue and operating results.

Our top four customers represented approximately 77% of our total revenue for the year ended December 31, 2018. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers for the foreseeable future. Loss of one of these purchasers could adversely affect our revenues in the short term.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, certain lossesthese risks.

We are not insured against all risks. Losses and liabilities arising from itsuninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. However, it is impossible

Our development activities are subject to insure against all operationalof the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

environmental hazards, such as unpermitted releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

abnormally pressured formations;

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

fires, explosions and ruptures of pipelines;

personal injuries and death;

natural disasters; and

terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in the coursesubstantial loss to us as a result of LINN’s business. Additionally, LINNclaims for:

injury or loss of life;

damage to and destruction of property, natural resources and equipment;

pollution and other environmental damage;

regulatory investigations and penalties;

suspension of our operations; and

repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if it believeswe believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsuredIn addition, pollution and environmental risks or in amounts in excess of existing insurance coverage.generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse impacteffect on LINN’sour business, activities, financial positioncondition and results of operations.

Because LINN handlesCertain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells. The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. As conditions in the oil and natural gas industry improve, demand for drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities will likely increase, as will the costs for those items. Any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to engage in our anticipated development activities could negatively impact our production volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability.

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other hydrocarbons,raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition,

possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our credit facility imposes certain limitations on our ability to enter into acquisition transactions. Our credit facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

Competition in the oil and natural gas industry is intense, making it may incur significant costsmore difficult for us to acquire properties, market oil or natural gas and liabilitiessecure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future resulting fromwill depend on our ability to evaluate and select suitable properties and to consummate transactions in a failurehighly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to complypay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

We may be subject to risks in connection with new or existing environmental regulations or an accidental releaseacquisitions of hazardous substances into the environment.properties.

The operationssuccessful acquisition of LINN’s wells, gathering systems, turbines, pipelinesproducing properties requires an assessment of several factors, including:

recoverable reserves;

future oil and natural gas prices and their applicable differentials;

operating costs; and

potential environmental and other facilitiesliabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an“as-is” basis.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

Oil and gas exploration and production activities are complex and involve risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course of our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change materially from one period to the next.

We are subject to stringent and complex federal, state and local environmental laws and regulations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. There is an inherent risk that LINN may incur environmental costs and liabilities duerelated to the nature of its business and the substances it handles. Certain environmental statutes, including the RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. In addition, an accidental release from one of LINN’s wells or gathering pipelines could subject it to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.

Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase LINN’s compliance costs and the cost of any remediation that may become necessary, and these costs may not be recoverable from insurance. For a more detailed discussion of environmental and regulatory matters impacting LINN’s business, please read “Business—LINN—Environmental Mattersoccupational health and Regulation.”

LINN is subject to complex federal, state, local and other laws and regulationssafety issues that could adversely affect the cost, manner or feasibility of doing business.conducting our operations or expose us to significant liabilities.

LINN’sOur operations are regulated extensively at thesubject to numerous stringent and complex federal, state and local levels. Environmental and other governmental laws and regulations have increasedgoverning, among other things, occupational safety and health aspects of our operations, the costs to plan, design, drill, install, operatedischarge of materials into the environment (such as the venting or flaring of natural gas and abandon oil

Index to Financial Statements

the emission of GHGs and other air pollutants), the generation, management and disposal of solid or hazardous wastes and the protection of the environment and natural gas wells. Underresources (including threatened and endangered species). These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting drilling and other regulated activities; the restriction of types, quantities and concentration of materials that may be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations, and reclamation and restoration costs. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations LINN could also be liable for personal injuries, property damage and other damages.the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the suspensionassessment of sanctions, including administrative, civil or terminationcriminal penalties, natural resource damages, the imposition of LINN’sinvestigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations or specific projects and limit our growth and revenue.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject it to administrative, civilstrict, joint and criminal penalties. Moreover, public interestseveral liability for the investigation, removal or remediation of contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations, regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with previous standards in the industry at the time they were conducted. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. We may not be able to recover some or any of these costs from insurance.

The trend in environmental protectionregulation has increasedbeen towards more stringent requirements, and any changes that result in recent years,more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which LINN operates includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drillingmaintain compliance and production activities. In addition, LINN’s activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect LINN’s operations and limit the quantity of oil, natural gas and NGL it may produce and sell. A major risk inherent in LINN’s drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs couldotherwise have a material adverse effect on LINN’sour results of operations, competitive position or financial condition. For example, in October 2015, the EPA issued a final rule under the federal Clean Air Act (“CAA”), lowering the National Ambient Air Quality Standard (“NAAQS”) for ground level ozone from the current standard of 75 parts per billion (“ppb”) for the current 8 hour primary and secondary ozone standards to 70 ppb for both standards, and completedattainment/non-attainment designations in July 2018. States are expected to implement more stringent permitting and pollution control requirements as a result of this final rule, which could apply to our operations. While the EPA has determined that all counties in which we operate are in attainment with the new ozone standards, these determinations may be revised in the future. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new facilities or modify existing facilities in these newly designatednon-attainment areas. Separately, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. Compliance with these and other more stringent air pollution control and permitting standards and other environmental regulations could delay or prohibit our ability to develop its properties. Additionally, the regulatory environment could change in ways that might substantiallyoil and natural gas projects and increase the financial and managerialour costs of compliance with these lawsdevelopment and regulationsproduction, the costs of which could be significant. Please see “Business—Regulation of the Oil and consequently, adversely affect LINN’s ability to pay distributions to its unitholders. ForNatural Gas Industry—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of the laws and regulations that affect us.

Restrictions on drilling activities intended to protect certain species of wildlife and their habitat may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife and their habitat. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. For example, in November 2016, the U.S. Fish and Wildlife Service (“FWS”) completed initial reviews of a petition filed by environmental groups to list the Lesser Prairie Chicken as endangered and found substantial information that the petitioned action may be warranted. An assessment of the biological status of the Lesser Prairie Chicken began in 2015, and further action remains pending. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us please readto incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.

Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005 (“EPAct 2005”), the Federal Energy Regulatory Commission (the “FERC”) has civil penalty authority under the Natural Gas Act of 1938 (“NGA”) to impose penalties for current violations of up to approximately $1.2 million per day for each violation. The FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwisenon-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time.

Additionally, the Federal Trade Commission (“FTC”) has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to approximately $1.2 million per day, and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti manipulation authority with respect to swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of approximately $1.1 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—LINN—Environmental MattersRegulation of the Oil and Regulation.Natural Gas Industry.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified large GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations. Recent federal regulatory action with respect to GHG emissions from the oil and natural gas sector has focused on methane emissions. For example, in June 2016, the EPA published performance standards, known as Subpart OOOOa for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. Following the changes in presidential administration, there have been attempts to modify the regulations and litigation concerning the regulations is pending. The BLM also finalized a similar rule regarding the control of methane emissions in November 2016 that applies to oil and natural gas exploration and development activities on public and tribal lands. In September 2018, the BLM issued a final rule rescinding the agency’s 2016 methane rule, and litigation challenging the rescission is pending. As a result of the developments described above, substantial uncertainty exists with respect to implementation of the EPA and BLM methane rules. However, given the long-term trend towards increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities.

There has not been significant activity in the form of federal legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets (“Paris Agreement”). The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does impose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not possible at this time to predict how new laws or regulations in the United States or any legal requirements imposed by the Paris Agreement on the United States, should it not withdraw from the agreement, that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations as well as result in delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil, natural gas and NGLs we produce and lower the value of our reserves. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil an gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Oklahoma forced pooling system, could have a material adverse effect on our business.

Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells we drill and the disposal of saltwater produced from such wells, among other matters. Changes in the legal and regulatory environment governing our industry, particularly any changes to Oklahoma statutory forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business and operating results.

Federal, state and state legislationlocal legislative and regulatory initiatives relatedrelating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays.delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbonsoil and/or natural gas from tightdense subsurface rock formations. DueWe regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to concerns raised relatingfracture the surrounding rock and stimulate production.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting and separately published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on groundwater quality, legislativedrinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. In addition, the BLM finalized rules in March 2015 establishing stringent standards relating to hydraulic fracturing on federal and American Indian lands, including well casing and wastewater storage requirements and an obligation for exploration and production operators to disclose what chemicals they are using in fracturing activities. However, in December 2017, BLM issued a final rule repealing the 2015 hydraulic fracturing rule, and litigation regarding this rescission is pending.

Additionally, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, but, at this time, federal legislation related to hydraulic fracturing appears unlikely. At the state level, some states, including Oklahoma, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure, operational or well construction requirements on hydraulic fracturing activities, or that prohibit hydraulic altogether. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

In the event that a new, federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we may incur additional costs to comply with such requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities, which could in turn have a material adverse effect on our business and results of operations.

Please see “Business—Regulation of the Oil and Natural Gas Industry—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of the laws and regulations that affect us.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as3-D seismic data, requires greaterpre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.

Legislation or regulatory efforts atinitiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of saltwater gathered from such activities, which could limit the Company’s ability to produce oil and natural gas economically and have a material adverse effect on our business.

State and federal levelregulatory agencies continue to study a possible connection between hydraulic fracturing related activities and the increased occurrence of seismic activity. We have experienced, and may in the future experience, seismic events in connection with our drilling and completion activities. Certain of these events, if above certain levels, may result in suspension of drilling or completion activities by the Oklahoma Corporation Commission (“OCC”). For example in November 2018, we temporarily suspended operations on one of our wells in Grady County due to seismic activity per OCC regulations.

In response to seismic concerns, regulators in some states have been initiatedadopted, and other states are considering adopting, additional requirements related to render permittingproduced water disposal wells to improve seismic safety. For example, in Oklahoma, the OCC has implemented a variety of measures including the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and complianceother factors in determining whether such wells should be permitted, permitted only with restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has rules requiring operators of certain saltwater disposal wells in the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC, from time to time, has developed and

implemented plans calling for wells within areas of interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents.

We dispose of large volumes of saltwater gathered from our drilling and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent foroperating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

In addition, we could be subject to third-party lawsuits alleging damages resulting from seismic events that occur in our areas of operation. The adoption and implementation of any new laws, regulations or orders that restrict our ability to use hydraulic fracturing or prohibit the activity altogether. For example, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Programdispose of saltwater gathered from our drilling and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, both Texas and Louisiana have adopted disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic fracturing fluids. Such effortsproduction activities could have ana material adverse effect on LINN’sour business, financial condition and results of operations.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas production activities. Forindustry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more detailed discussion of hydraulic fracturing matters impacting LINN’sthe technologies we use now or in the future were to become obsolete, our business, please read “Business—LINN—Environmental Mattersfinancial condition or results of operations could be materially and Regulation.”adversely affected.

Risks Inherent in an Investment in LinnCo

Our cash flow consists exclusively of distributions from LINN.business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

Our only assets will be units representing limited liability company interests in LINN that we own. Our cash flow will be therefore completely dependent upon the ability of LINN to make distributions to its unitholders. The amount of cash that LINN can distribute to its unitholders, including us, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

produced volumes of oil, natural gas and NGL;

prices at whichAs an oil, natural gas and NGL production is sold;producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.

Loss of our information and computer systems could adversely affect our business.

We are dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, natural gas and NGLs and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

levelRisks Related to Our Class A Common Stock

The requirements of its operating costs;

paymentbeing a public company, including compliance with the reporting requirements of interest,the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As the successor registrant to New Linn, we must comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), related regulations of the SEC with which depends on thewe were not required to comply as a private company. Complying with these statutes, regulations and requirements occupies a significant amount of its indebtedness and the interest payable thereon; and

leveltime of its capital expenditures.

Index to Financial Statements

In addition, the actual amount of cash that LINN will have available for distribution will depend on other factors, some of which are beyond its control, including:

availability of borrowings on acceptable terms under its credit facility to pay distributions;

the costs of acquisitions, if any;

fluctuations in its working capital needs;

timing and collectibility of receivables;

restrictions on distributions contained in its credit facility and the indentures governing its senior notes;

prevailing economic conditions;

access to credit or capital markets; and

the amount of cash reserves established by itsour board of directors and management and significantly increases our costs and expenses. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.

We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. Furthermore, while we generally must comply with Section 404 of the Sarbanes-Oxley Act for our fiscal year ending December 31, 2018, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until we cease to be anon-accelerated filer. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

We have identified material weaknesses in our internal control over financial reporting; failure to achieve and maintain effective internal control over financial reporting could have a material adverse effect on our business.

We have identified material weaknesses in our internal control over financial reporting in connection with the audit of our financial statements as of and for the proper conductyears ended December 31, 2018, 2017 and 2016. A material weakness is a deficiency, or a combination of its business.deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

We have identified the following material weaknesses in our internal control over financial reporting.

We had an overall lack of qualified personnel within the organization who possessed an appropriate level of expertise, experience and training to effectively design, implement and maintain:

(i)

adequate controls to monitor and assess the control environment. Specifically, internal controls were not designed or operating effectively to ensure appropriate monitoring or assessment of the control environment, including utilizing an appropriate framework.

(ii)

adequate controls to establish appropriate entity level controls. Specifically, internal controls were not designed or operating effectively to ensure a sufficient amount of entity level controls were in place and operating effectively;

(iii)

effective controls over ourperiod-end financial reporting processes, including controls over the preparation, analysis and review of certain significant account reconciliations required to assess the appropriateness of account balances atperiod-end; and controls over segregation of duties and the review of manual journal entries. Specifically, we did not design and maintain effective controls to verify that journal entries were properly prepared with sufficient supporting documentation or were reviewed and approved to ensure the accuracy and completeness of the manual journal entries. Additionally, certain key accounting personnel have the ability to prepare and post journal entries, as well as review account reconciliations, without an independent review by someone other than the preparer;

(iv)

effective controls over information technology systems that are relevant to the preparation of the financial statements. Specifically, we did not design and maintain (a) user access controls to ensure appropriate segregation of duties and to adequately restrict user and privileged access to infrastructure, financial applications, programs, and data to appropriate personnel, (b) program change management controls to ensure that information technology program and data changes affecting financial IT applications and underlying accounting records are identified, tested, authorized and implemented appropriately, (c) computer operation controls to ensure all financially significant batch jobs are monitored for the completeness and accuracy of data transfer, and (d) program development controls to ensure that new software development is aligned with business and IT requirements. The deficiencies described in this clause (iv), when aggregated, could impact both maintaining effective segregation of duties and the effectiveness ofIT-dependent controls (such as automated controls that address the risk of material misstatement to one or more assertions, along with the IT controls and underlying data that support the effectiveness of system-generated data and reports) that could result in misstatements potentially impacting all financial statement accounts and disclosures that would not be prevented or detected in a timely manner;

(v)

effective controls over our reservoir engineering process for estimating proved oil, natural gas and NGL reserves, which are used in the calculation of depletion of the Company’s oil and natural gas properties. Specifically, we did not maintain effective controls to verify that the Company’s ownership interests in its oil and natural gas properties used in the reservoir engineering process are sufficiently reviewed to ensure completeness and accuracy of the information; and

(vi)

a sufficient complement of resources with an appropriate level of accounting knowledge, experience and training to develop and maintain an effective internal control environment.

These material weaknesses did not result in any material misstatements of our financial statements or disclosures. The material weaknesses could, however, result in a misstatement of account balances or disclosures that would result in a material misstatement to the annual or interim financial statements that would not be prevented or detected.

Because of these factors, LINN maymaterial weaknesses, management has concluded that the Company’s internal control over financial reporting was not have sufficient available cash each quarter to pay the current distributioneffective as of $0.725 per quarter or any other amount. Furthermore, the amount of cash that LINN has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, LINN may be able to make cash distributions during periods when it records net losses and may not be able to make cash distributions during periods when it records net income. Please read “—Risks Related to LINN’s Business” for a discussion of risks affecting LINN’s ability to generate distributable cash flow.

We will incur corporate income tax liabilities on income allocated to us by LINN with respect to LINN units we own, which may be substantial.December 31, 2018.

We are classified as a corporation for U.S. federal income tax purposeshave taken and in most states in which LINN does business, for state income tax purposes. Under current law, we will be subjectcontinue to U.S. federal income tax at rates of up to 35% (and a 20% alternative minimum tax in certain cases), and to state income tax at rates that vary from state to state, on the net income allocated to us by LINN with respect to the LINN units we own. The amount of cash available for distribution to you will be reduced by the amount of any such income taxes payable by us for which we establish reserves.

Although we currently estimate that our income tax liability for each of the periods ending December 31, 2012, 2013, 2014 and 2015 will not exceed     % of the distributions we receive from LINN with respect to the applicable period (please read “Our Dividend Policy”), that estimate is based upontake a number of assumptionsactions to remediate these material weaknesses. We have implemented measures designed to improve our internal control over financial reporting and remediate the control deficiencies that may prove incorrect. Events inconsistentled to the material weaknesses. We have hired additional IT and accounting personnel with appropriate technical skillsets and initiated design and implementation of our assumptionscontrol environment, including the expansion of formal accounting and IT policies and procedures and financial reporting controls. We are continuing to (i) conduct a company-wide assessment of our control environment, (ii) implement appropriate review and oversight responsibilities within the accounting, financial reporting, and reservoir engineering functions and (iii) evaluate controls over our information technology environment. To remediate our existing material weaknesses, we require additional time to complete the implementation of our remediation plans and

demonstrate the effectiveness of our remediation efforts. The material weaknesses cannot be considered remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that could causethese controls are operating effectively. We can give no assurance that these actions will remediate these material weaknesses in internal controls or that additional material weaknesses in our income tax liabilities tointernal control over financial reporting will not be substantially higher than estimated (and could therefore cause our quarterly dividends to be substantially lower than the quarterly distributions on LINN units) include:

a significant decrease in drilling activity by LINN;

an issuance of significant additional units by LINN without a corresponding increaseidentified in the aggregate tax deductions generated by LINN;future.

the enactment of proposed legislation that would eliminate the current deduction of intangible drilling costsAn active, liquid and other tax incentives to the oil and natural gas industry; and

a significant increase in oil and natural gas prices.

Moreover, after December 31, 2015, our income tax liabilities may increase substantially. For example, distributions that we receive with respect to our LINN units that exceed the net income allocated to us by LINN with respect to those units decrease our tax basis in those units. When our tax basis in our LINN units is reduced to zero and any loss or other carryovers are fully utilized, the distributions we receive from LINN in excess of net income allocated to us by LINN will effectively be fully taxable to us, without any deductions.

Index to Financial Statements

Changes to current U.S. federal tax laws may affect our ability to take certain tax deductions.

Substantive changes to the existing U.S. federal income tax laws have been proposed that, if adopted, would affect, among other things, our ability to take certain deductions related to LINN’s operations, including deductions for intangible drilling costs and percentage depletion and deductions for costs associated with U.S. production activities. We are unable to predict whether any changes, or other proposals to such laws, ultimately will be enacted. Any such changes could negatively impact the value of an investment in our shares.

There is no existing market for our shares. Following this offering, an activeorderly trading market for our sharesClass A common stock may not develop or be maintained, and even if such a market does develop, the marketour stock price of our shares may be volatile.

Upon any future listing by us on a national securities exchange, an active, liquid and orderly trading market for our Class A common stock may not develop or be maintained. Active, liquid and orderly trading markets usually result in less than the price you paid for your sharesvolatility and less than the market price of LINN units.more efficiency in carrying out investors’ purchase and sale orders. The market price of our shares may fluctuateClass A common stock could vary significantly and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our shares. After this offering, there will be only                 publicly traded shares, assuming no exercise of the underwriters’ option to purchase additional shares. We do not know the extent to which investor interest will lead to the developmentas a result of a trading market or how liquid that market might be. You may not be able to resell your shares at or above the initial public offering price.

The initial public offering price for the shares will be determined by negotiations between us and the representativesnumber of the underwriters and may not be indicative of the market price of the shares that will prevail in the trading market. The market price of our shares may decline below the initial public offering price. The market price of our shares may also be influenced by many factors, some of which are beyond our control, including:control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock. Consequently, you may not be able to sell shares of our Class A common stock at prices equal to or greater than the price paid by you.

The following factors could affect our stock price:

 

our operating and financial performance and drilling locations, including reserve estimates;

quarterly variations in the trading pricerate of LINN units;growth of our financial indicators, such as net income per share, net income and revenues;

 

the level of LINN’s quarterly distributionspublic reaction to our press releases, our other public announcements and our quarterly dividends;filings with the SEC;

 

LINN’s quarterlystrategic actions by our competitors;

changes in revenue or annual earnings estimates, or thosechanges in recommendations or withdrawal of other companiesresearch coverage, by equity research analysts;

speculation in its industry;the press or investment community;

 

the lossfailure of a large customer by LINN;research analysts to cover our Class A common stock;

 

announcementssales of our Class A common stock by LINNus or its competitors of significant contractsthe selling stockholders or acquisitions;the perception that such sales may occur;

 

changes in accounting standards,principles, policies, guidance, interpretations or principles;standards;

additions or departures of key management personnel;

actions by our stockholders;

general market conditions, including fluctuations in commodity prices;

domestic and international economic, legal and regulatory factors unrelated to our performance; and

the realization of any risks described under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

The concentration of our capital stock ownership among our largest stockholders and their affiliates will limit your ability to influence corporate matters.

Our principal stockholders and their affiliates beneficially own approximately 75% (50% of which is beneficially owned by Roan Holdings) of our outstanding Class A common stock. Consequently, they will continue to have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. Because our board will be classified

through the 2020 annual meeting, certain of our directors will not come up for election until after the 2020 annual meeting. This concentration of ownership and the rights of our principal stockholders will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

In connection with the Reorganization, we entered into a stockholders’ agreement with the principal stockholders. The stockholders’ agreement provides the principal stockholders with the right to designate a certain number of nominees to our board of directors through the 2020 annual meeting so long as the principal stockholders and their affiliates collectively beneficially own certain amounts of the outstanding shares of our Class A common stock. The existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the concentration of stock ownership may adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and our principal stockholders and their respective affiliates, including portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Several of our principal stockholders are private equity firms or investment funds in the business of making investments in entities in a variety of industries. As a result, our principal stockholders’ existing and future portfolio companies may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor. Certain of our principal stockholders owning approximately 25% of our outstanding Class A common stock own a significant interest in Riviera Resources, Inc., the owner of Blue Mountain Midstream, LLC. Please see “Certain Relationships and Related Party Transactions—Historical Transactions with Affiliates—Riviera Resources, Inc.”

Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including affiliates of our principal stockholders) that are in the business of identifying and acquiring oil and natural gas properties. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. Messrs. Taylor, Lederman and Bonanno serve on the board of directors of Riviera Resources, Inc., the owner of Blue Mountain Midstream, LLC. Messrs. Lovoi and Loyd were members of the board of directors of Jones Energy, Inc. Please see “Certain Relationships and Related Party Transactions—Historical Transactions with Affiliates.”

None of the principal stockholders, nor any of their respective affiliates are limited in their ability to compete with us, and the corporate opportunity provisions in our second amended and restated certificate of incorporation could enable each of them to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents provide that our principal stockholders and each of their respective affiliates (including portfolio investments of any of them) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our second amended and restated certificate of incorporation, among other things:

permits such persons to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

provides that if any of such persons or any employee, partner, member, manager, officer or director of any of such persons who is also one of our directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Our principal stockholders or their respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, our principal stockholders or their respective affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our principal stockholders or their respective affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please see “Description of Capital Stock—Corporate Opportunity.”

Our second amended and restated certificate of incorporation and second amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Our second amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our second amended and restated certificate of incorporation and second amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

limitations on the removal of directors;

limitations on the ability of our stockholders to call special meetings;

establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

providing that the board of directors is expressly authorized to adopt, or to alter or repeal our second amended and restated bylaws; and

establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Our second amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our second amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our second amended and restated certificate of incorporation or our second amended and restated bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Section 27 of the Exchange Act provides: “The district courts of the United States ... shall have exclusive jurisdiction of violations of [the Exchange Act] or

the rules and regulations thereunder, and of all suits in equity and actions at law brought to enforce any liability or duty created by [the Exchange Act] or the rules and regulations thereunder.” As a result, the exclusive forum provision will not apply to actions arising under the Exchange Act or the rules and regulations thereunder. However, Section 22 of the Securities Act provides for concurrent federal and state court jurisdiction over actions under the Securities Act and the rules and regulations thereunder, subject to a limited exception for certain “covered class actions” as defined in Section 16 of the Securities Act and interpreted by the courts. Accordingly, we believe that the exclusive forum provision would apply to actions arising under the Securities Act or the rules and regulations thereunder, except to the extent a particular action fell within the exception for covered class actions or one of the exceptions in the second amended and restated certificate of incorporation described above otherwise applied to such action, which could occur if, for example, the action also involved claims under the Exchange Act.

Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our second amended and restated certificate of incorporation described in the preceding paragraph. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our second amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

We do not intend to pay cash dividends on our Class A common stock, and our credit facility places certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our Class A common stock appreciates.

We do not plan to declare cash dividends on shares of our Class A common stock in the foreseeable future. Additionally, our credit facility places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your Class A common stock at a price greater than you paid for it. There is no guarantee that the price of our Class A common stock that will prevail in the market will ever exceed the price that you paid for it.

Future sales of our Class A common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of Class A common stock in one or more future public offerings. We may also issue additional shares of Class A common stock or securities convertible into Class A common stock. We have 152,539,532 outstanding shares of Class A common stock. We are authorized to issue 800,000,000 shares of Class A common stock and 50,000,000 shares of preferred stock with such designations, preferences and rights as determined by our board of directors. The potential issuance of such additional shares of equity securities will result in the dilution of the ownership interests of the holders of our Class A common stock and may create downward pressure on the trading price, if any, of our Class A common stock. The registration rights of the selling stockholders and the sales of substantial amounts of our Class A common stock following the effectiveness of shelf registration statements for the benefit of such holders, or the perception that these sales may occur, could cause the market price of our Class A common stock to decline and impair our ability to raise capital. We also may grant additional registration rights in connection with any future issuance of our capital stock.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

We may issue preferred stock the terms of which could adversely affect the voting power or value of our Class A common stock.

Our second amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus.

Forward-looking statements may include statements about:

our business strategy;

our reserves;

our drilling plans, prospects, inventories, projects and programs;

our ability to replace the reserves we produce through drilling and property acquisitions;

our financial strategy, liquidity and capital required for our drilling program and timing related thereto;

our realized oil, natural gas and NGL prices;

the timing and amount of our future production of oil, natural gas and NGLs;

our competition and government regulations;

our ability to obtain permits and governmental approvals;

our pending legal or environmental matters;

our marketing of oil, natural gas and NGLs;

our leasehold or business acquisitions;

our costs of developing our properties;

our hedging strategy and results;

 

general economic conditions;

 

credit markets;

uncertainty regarding our future salesoperating results including initial production values and liquid yields in our type curve areas;

the costs, terms and availability of our shares;gathering, processing, fractionation and other midstream services; and

 

other factors describedour plans, objectives, expectations and intentions contained in these “Risk Factors.”

Our shareholders will only be able to indirectly vote on matters on which LINN unitholders are entitled to vote, and our shareholdersthis prospectus that are not entitled to vote to elect our directors.historical.

Our shareholders will only be able to indirectly vote on matters on which LINN unitholders are entitled to vote, and our shareholders are not entitled to vote to elect our directors. Therefore,We caution you will only be able to indirectly influence the management and board of directors of LINN, and you will not be able to directly influence or change our management or board of directors. If our shareholders are dissatisfied with the performance of our directors, they will have no ability to remove the directors and will have no right on an annual or ongoing basis to elect our board of directors. Rather, our board of directors will be appointed by the holder of our voting share, which will be LINN. As a result ofthat these limitations, the price at which the shares will trade could be lower because of the absence or reduction of a takeover premium in the trading price. Our limited liability company agreement also contains provisions limiting the ability of holders of our shares to call meetings or to obtain information about our operations, as well as other provisions limiting the ability of holders of our shares to influence the manner or direction of management.

Index to Financial Statements

LINN may issue additional units without your approval or other classes of units, and we may issue additional shares, which would dilute our direct and your indirect ownership interest in LINN and your ownership interest in us.

LINN’s limited liability company agreement does not limit the number of additional limited liability company interests, including interests that rank senior to the LINN units, that it may issue at any time without the approval of its unitholders. The issuance by LINN of additional units or other equity securities of equal or senior rank will have the following effects:

our proportionate ownership interest in LINN will decrease;

the amount of cash available for distribution on each LINN unit may decrease, resulting in a decrease in the amount of cash available to pay dividends to you;

the relative voting strength of each previously outstanding unit, including the LINN units we hold and vote in accordance with the vote of our unitholders, will be diminished; and

the market price of the LINN units may decline, resulting in a decline in the market price of our shares.

In addition, our limited liability company agreement does not limit the number of additional shares that we may issue at any time without your approval. The issuance by us of additional shares will have the following effects:

your proportionate ownership interest in us will decrease;

the relative voting strength of each previously outstanding share you own will be diminished; and

the market price of our shares may decline.

Your shares are subject to limited call rights that could result in your having to involuntarily sell your shares at a time or price that may be undesirable.

If LINN or any of its affiliates owns 80% or more of our outstanding shares, LINN has the right, which it may assign to any of its affiliates, to purchase all of our remaining outstanding shares, at a purchase price not less than the then-current market price of our shares. If LINN exercises any of its rights to purchase our shares, you may be required to sell your shares at a time or price that may be undesirable, and you could receive less than you paid for your shares. Any sale of our shares, to LINN or otherwise, for cash will be a taxable transaction to the owner of the shares sold. Accordingly, a gain or loss will be recognized on the sale equal to the difference between the cash received and the owner’s tax basis in the shares sold.

In addition, if at any time a person owns more than 90% of the outstanding LINN units, such person may elect to purchase all, but not less than all, of the remaining outstanding LINN units at a price equal to the higher of the current market price (as defined in LINN’s limited liability company agreement) and the highest price paid by such person or any of its affiliates for any LINN units purchased during the 90-day period preceding the date notice was mailed to the LINN unitholders informing them of such election. In this case, we will be required to tender all of our outstanding LINN units and distribute the cash we receive, net of income taxes payable by us, to our shareholders. Following such distribution, we will dissolve and wind up our affairs. Thus, upon the election of a holder of 90% of the outstanding LINN units, you may receive a distribution that is effectively less than the price at which you would prefer to sell your shares.

The terms of our shares may be changed in ways you may not like, because our board of directors will have the power to change the terms of our shares in ways our board determines, in its sole discretion, are not materially adverse to you.

As an owner of our shares, you may not like the changes made to the terms of our shares, if any, and you may disagree with our board of directors’ decision that the changes are not materially adverse to you as a

Index to Financial Statements

shareholder. Your recourse if you disagree will be limited because our limited liability company agreement gives broad latitude and discretion to our board of directors and limits the fiduciary duties that our officers and directors otherwise would owe to you.

Our limited liability company agreement limits the fiduciary duties owed by our officers and directors to our shareholders, and LINN’s limited liability company agreement limits the fiduciary duties owed by LINN’s officers and directors to its unitholders, including us.

Our limited liability company agreement has modified, waived and limited the fiduciary duties of our directors and officers that would otherwise apply at law or in equity and replaced such duties with a contractual duty requiring our directors and officers to act in good faith. For purposes of our limited liability company agreement, a person shall be deemed to have acted in good faith if the action or omission of action was taken with the belief that it was in, or not opposed to, the best interests of LinnCo and our shareholders. In addition, any action or omission shall be deemed to be in, or not opposed to, the best interests of LinnCo and our shareholders if such action or omission of action would be in, or not opposed to, the best interest of LINN and all its unitholders, taken together.

The above modifications of fiduciary duties are expressly permitted by Delaware law. Thus, we and our shareholders will only have recourse and be able to seek remedies against our board of directors if they breach their obligations pursuant to our limited liability company agreement. Furthermore, even if there has been a breach of the obligations set forth in our limited liability company agreement, that agreement provides that our directors and officers will not be liable to us or our shareholders, except for acts or omissions not in good faith.

These provisions restrict the remedies available to our shareholders for actions that without those limitations might constitute breaches of duty, including fiduciary duties. In addition, LINN’s limited liability company agreement also limits the fiduciary duties owed by LINN’s officers and directors to its unitholders, including us.

Our shares may trade at a substantial discount to the trading price of LINN units.

We cannot predict whether our shares will trade at a discount or premium to the trading price of LINN units. If we incur substantial corporate income tax liabilities on income allocated to us by LINN with respect to LINN units we own, the quarterly dividend of cash you receive per share will be substantially less than the quarterly per unit distribution of cash that we receive from LINN. In addition, upon a Terminal Transaction, the net proceeds you receive from us per share may, as a result of our corporate income tax liabilities on the transaction and other factors, be substantially lower than the net proceeds per unit received by a direct LINN unitholder. As a result of these considerations, our shares may trade at a substantial discount to the trading price of LINN units. See “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement—Terminal Transactions Involving LINN.”

We will be a “controlled company” within the meaning of the NASDAQ rules and intend to rely on exemptions from various corporate governance requirements immediately following the closing of this offering.

We intend to apply to list our shares on the NASDAQ Global Select Market. A company of which more than 50% of the voting power for the election of directors is held by an individual, a group or another company is a “controlled company” within the meaning of the NASDAQ rules. A “controlled company” may elect not to comply with various corporate governance requirements of NASDAQ, including the requirement that a majority of its board of directors consist of independent directors, the requirement that its nominating and governance committee consist of all independent directors and the requirement that its compensation committee consist of all independent directors.

Following this offering, we believe that we will be a “controlled company” since LINN will hold our sole voting share and will have the sole power to elect our board of directors. See “Description of the Limited

Index to Financial Statements

Liability Company Agreements—Our Limited Liability Company Agreement—Voting Rights.” Because we intend to rely on certain of the “controlled company” exemptions and will not have a compensation committee or a nominating and corporate governance committee, you may not have the same corporate governance advantages afforded to stockholders of companies thatforward-looking statements are subject to all of the corporate governance requirementsrisks and uncertainties, most of NASDAQ.which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” in this prospectus.

Tax Risks to Shareholders

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Upon a Terminal Transaction, we may be entitled to a smaller distribution per LINN unit we own than other LINN unitholders, and we may incur substantial corporate income tax liabilities in the transactionShould one or upon the distributionmore of the proceedsrisks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from the transaction to you,those expressed in which case the net proceeds you receive from us per share may be substantially lower than the net proceeds per unit received by a direct LINN unitholder.any forward-looking statements.

Upon a liquidation of LINN, LINN unitholders will receive distributionsAll forward-looking statements, expressed or implied, included in accordance with the positive balancesthis prospectus are expressly qualified in their respective capital accounts in their units. Please read “Description of the Limited Liability Company Agreements—LINN’s Limited Liability Company Agreement—Liquidation and Distribution of Proceeds.” As a result of the underwriting discount and offering expenses incurredentirety by this cautionary statement. This cautionary statement should also be considered in connection with this offering, we will acquire LINN units at a price lower than the current market price of LINN units. Therefore, our capital account in the LINN unitsany subsequent written or oral forward-looking statements that we will own initially will be lower than the capital accountsor persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of other LINN unitholders in their LINN units. Therefore, we would be entitled upon a dissolution of LINN to a smaller distribution per LINN unit we own than other LINN unitholders, unless adjustments were made to our capital accounts in the LINN units that we will own.

Each time LINN issues or redeems units, it is required to adjust the capital accounts in all outstanding LINN units upward to the extent of the “unrealized gains” in LINN’s assets or downward to the extent of the “unrealized losses” in LINN’s assets immediately prior to such issuance or redemption. In general, the difference between the fair market value of each such asset and its adjusted tax basis equals the unrealized gain (if the fair market value exceeds the adjusted tax basis) or the unrealized loss (if the adjusted tax basis exceeds the fair market value). Unrealized gains and unrealized losses generallywhich are allocated among the LINN unitholders in the same manner as other items of LINN income, gain, deduction or loss.

The board of directors of LINN, however, is authorized to make disproportionate allocations of income and deductions, including allocations of unrealized gains and unrealized losses, to the extent necessary to cause the capital accounts of all LINN units to be the same. We anticipate that there will be sufficient unrealized gains or unrealized losses in connection with future issuances or redemptions of LINN units in order for LINN to allocate to us sufficient unrealized gains, or to allocate sufficient unrealized losses to other holders of LINN units, to cause the capital accounts in the LINN units that we will own to be the same as the capital accounts of all other LINN units and result in our being entitled upon the dissolution of LINN to the same distribution per LINN unit we will own as other LINN unitholders. However, there can be no assurance that such adjustments will occur or that any adjustments that do occur will be sufficient to eliminate the difference between our capital account in the LINN units that we will own and the capital accounts of other LINN unitholders in their LINN units.

We are classified as a corporation for U.S. federal income tax purposes and, in most states in which LINN does business, for state income tax purposes. Upon a Terminal Transaction, we will be required to liquidate and distribute the net after-tax proceeds of the transaction to you. Please read “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement—Terminal Transactions Involving LINN.” We may incur substantial corporate income tax liabilities upon such a transaction or upon our distribution to you of the proceeds of the transaction. The tax liability we incur will depend in part upon the amount by which the value of the LINN units we own exceeds our tax basis in the units. We expect our tax basis in our LINN units to decrease over time as we receive distributions that exceed the net income allocated to us by LINN with respect to those units. As a result, we may incur substantial income tax liabilities upon such a transaction even if LINN

Index to Financial Statements

units decrease in value after we purchase them. The amount of cash or other property available for distribution to you upon our liquidation will be reducedexpressly qualified by the amountstatements in this section, to reflect events or circumstances after the date of any such income taxes paid by us. See “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement—Terminal Transactions Involving LINN.”this prospectus.

As a result of these factors, upon a Terminal Transaction, the net proceeds you receive from us per share may be substantially lower than the net proceeds per unit received by a direct LINN unitholder.

Your tax gain on the disposition of our shares could be more than expected, or your tax loss on the disposition of our shares could be less than expected.

If you sell your shares, or you receive a liquidating distribution from us, you will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and your tax basis in those shares. Because distributions in excess of your allocable share of our earnings and profits decrease your tax basis in your shares, the amount, if any, of such prior excess distributions with respect to the shares you sell or dispose of will, in effect, become taxable gain to you if you sell such shares at a price greater than your tax basis in those shares, even if the price you receive is less than your original cost. Please read “Material U.S. Federal Income Tax Consequences.”

If you are a U.S. holder of our shares, the IRS Forms 1099-DIV that you receive from your broker may over-report your dividend income with respect to our shares for U.S. federal income tax purposes, and failure to over-report your dividend income in a manner consistent with the IRS Forms 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your U.S. federal income tax return. If you are a non-U.S. holder of our shares, your broker or other withholding agent may overwithhold taxes from dividends paid to you, in which case you would have to file a U.S. tax return if you wanted to claim a refund of the overwithheld tax.

Dividends we pay with respect to our shares will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Dividends we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of your tax basis in your shares and then as capital gain realized on the sale or exchange of such shares. Please read “Material U.S. Federal Income Tax Consequences.” We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes.

If you are a U.S. holder of our shares, we may be unable to persuade brokers to prepare the IRS Forms 1099-DIV that they send to you in a manner that is consistent with our determination of the amount that constitutes a “dividend” to you for U.S. federal income tax purposes. We will attempt to timely notify you of available information to assist you with your income tax reporting (such as posting the correct information on our web site). However, the information that we provide to you may be inconsistent with the amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return.

If you are a non-U.S. holder of our shares, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with your conduct of U.S. trade or business. Please read “Material U.S. Federal Income Tax Consequences—Consequences to Non-U.S. Holders.” Because we may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes or we may be unable to persuade your broker or withholding agent to withhold taxes from distributions in a manner consistent with our determination of the amount that constitutes a “dividend” for such purposes, your broker or other withholding agent may overwithhold taxes from distributions paid to you. In such a case, you would have to file a U.S. tax return to claim a refund of the overwithheld tax.

Index to Financial Statements

If LINN were subject to a material amount of entity-level income taxes or similar taxes, whether as a result of being treated as a corporation for U.S. federal income tax purposes or otherwise, the value of LINN units would be substantially reduced and, as a result, the value of our shares would be substantially reduced.

The anticipated benefit of an investment in LINN units depends largely on the assumption that LINN will not be subject to a material amount of entity-level income taxes or similar taxes, and the anticipated benefit of an investment in our shares depends largely upon the value of LINN units.

LINN may be subject to material entity-level U.S. federal income tax and state income taxes if it is treated as a corporation, rather than as a partnership, for U.S. federal income tax purposes. Because LINN’s units are publicly traded, Section 7704 of the Internal Revenue Code requires that LINN derive at least 90% of its gross income each year from the marketing of oil and natural gas, or from certain other specified activities, in order to be treated as a partnership for U.S. federal income tax purposes. We believe that LINN has satisfied this requirement and will continue to do so in the future, so we believe LINN is and will be treated as a partnership for U.S. federal income tax purposes. However, we have not obtained a ruling from the U.S. Internal Revenue Service regarding LINN’s treatment as a partnership for U.S. federal income tax purposes. Moreover, current law or the business of LINN may change so as to cause LINN to be treated as a corporation for U.S. federal income tax purposes or otherwise subject LINN to material entity-level U.S. federal income taxes, state income taxes or similar taxes. Any modification to current law or interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the requirements for partnership status, affect or cause LINN to change its business activities, change the character or treatment of portions of LINN’s income and adversely affect our investment in LINN units.

If LINN were treated as a corporation for U.S. federal income tax purposes, it would be subject to U.S. federal income tax at rates of up to 35% (and a 20% alternative minimum tax in certain cases), and to state income tax at rates that vary from state to state, on its taxable income. Distributions from LINN would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to LINN unitholders. Any income taxes or similar taxes imposed on LINN as an entity, whether as a result of LINN’s treatment as a corporation for U.S. federal income tax purposes or otherwise, would reduce LINN’s cash available for distribution to its unitholders. Any material reduction in the anticipated cash flow and after-tax return to LINN unitholders would reduce the value of the LINN units we own and the value of our shares. In addition, if LINN were treated as a corporation for U.S. federal income tax purposes, that would constitute a Terminal Transaction. See “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement—Terminal Transactions Involving LINN.”

Also, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity level taxation through the imposition of state income, franchise or other forms of taxation. For example, LINN is required to pay Texas franchise tax at a maximum effective rate of 0.7% of its total revenue apportioned to Texas in the prior year. Imposition of a tax on LINN by any other state would reduce the amount of cash available for distribution to us.

Index to Financial Statements

USE OF PROCEEDS

We are registering these shares of Class A common stock for resale by the selling stockholders. We will use the estimated net proceeds of approximately $        million from this offering ($        million if the underwriters exercise their option to purchase additional shares in full), after deducting underwriting discounts, to purchase from LINN a number of LINN units equal to the number of shares sold in this offering. The per unit price we will pay for such LINN units will be equal to the net proceeds wenot receive on a per share basis. LINN will pay our expenses incurred in connection with this offering.

LINN will use the proceeds it receives from the sale of LINN units to us for general corporate purposes, including financing its acquisition strategy, repaying debt and paying the expenses of this offering.

Affiliates of certain of the underwriters in this offering are lenders under LINN’s Credit Facility and, accordingly, if LINN elects to use the proceeds it receives from LinnCo to repay debt outstanding under its Credit Facility, those lenders would indirectly receive a portion of the netany proceeds from this offering. Please read “Underwriting—FINRA Rules.”

Index to Financial Statements

CAPITALIZATION OF LINNCO

The following table sets forth our capitalization as of April 30, 2012:

on an historical basis; and

on an adjusted basis to give effect to the sale of shares offered by us at an assumed initial public offering pricethis prospectus.

DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of $        per share (the midpointour Class A common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our credit facility places restrictions on our ability to pay cash dividends.

SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

Roan Resources, Inc. was incorporated in September 2018 to serve as a holding company and, prior to the Reorganization, had no previous operations, assets or liabilities. The historical financial information included in this prospectus (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is that of Roan LLC, our predecessor. The historical financial and operational information of Roan LLC presented in this prospectus, (i) prior to August 31, 2017, the date of the range set forthcompletion of the Contribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the cover pagehistorical financial and operational information of Citizen prior to August 31, 2017 does not include financial information relating to the oil and natural gas assets contributed to Roan LLC by Old Linn in connection with the Contribution.

The selected historical statement of operations data for the years ended December 31, 2018, 2017 and 2016 was derived from the audited historical financial statements of Roan Inc. included elsewhere in this prospectus), after deducting underwriting discounts,prospectus. The selected historical balance sheet data as of December 31, 2018 and 2017 was derived from the audited historical financial statements of Roan Inc. included elsewhere in this prospectus. The selected historical balance sheet data as of December 31, 2016 and the applicationbalance sheet and statement of operations data as of and for the year ended December 31, 2015 was derived from audited financial statements and the notes thereto that are not included in this prospectus. The selected historical balance sheet and statement of operations data as of and for the period ended December 31, 2014 was derived from the unaudited financial statements of our predecessor that are not included in this prospectus. The summary unaudited historical interim condensed financial data as of and for the three months ended March 31, 2019 and 2018 was derived from our unaudited interim condensed financial statements included elsewhere in this prospectus. The summary unaudited historical condensed interim financial data has been prepared on a consistent basis with the audited financial statements of Roan Inc. In the opinion of management, such summary unaudited historical condensed interim financial data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented. The results of operations for the interim periods are not necessarily indicative of the net proceeds as describedresults that may be expected for the full year because of the impact of fluctuations in “Useprices received for oil and natural gas, natural production declines, the uncertainty of Proceeds.”exploration and development drilling results and other factors.

Our historical results are not necessarily indicative of future results. You should read this table together with “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

   At April 30, 2012 
   Historical   As Adjusted 

Equity

    

Voting share

  $1,000    $1,000  

Non-voting shares

   —      
  

 

 

   

 

 

 

Total capitalization

  $1,000    $   
  

 

 

   

 

 

 

Index to Financial Statements

CAPITALIZATION OF LINN

Thethe following table sets forth the cash and cash equivalents and consolidated capitalization of Linn Energy, LLC at March 31, 2012:

on an historical basis; and

on an adjusted basis to give effect to the offering and sale of                 LINN units to LinnCo at an assumed price of $        per LINN unit (based on the midpoint of the range set forth on the cover page of this prospectus), after deducting estimated offering expenses, and the application of the net proceeds as described in “Use of Proceeds.”

The following table is unaudited and should be read togetherconjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and LINN’sthe historical and pro forma financial statements and the relatedaccompanying notes thereto included elsewhere in this prospectus.

The selected unaudited pro forma condensed statement of operations data for the year ended December 31, 2018 has been prepared to give pro forma effect to the Reorganization as if it had occurred on January 1, 2018. The selected unaudited pro forma condensed financial data is provided for illustrative purposes only and is not indicative of the results that actually would have occurred had the transactions been in effect on the dates or for the periods indicated, or of results that may occur in the future.

   At March 31, 2012 
   Historical   As Adjusted 
   (in thousands) 

Cash and cash equivalents(1)

  $24,184    $              
  

 

 

   

 

 

 

Long-term debt:

    

Credit Facility(2)

  $75,000    $   

2017 notes, net

   39,235    

2018 notes, net

   13,919    

May 2019 notes, net

   744,737    

November 2019 notes, net

   1,799,803    

2020 notes, net

   1,272,435    

2021 notes, net

   984,413    
  

 

 

   

 

 

 

Total long-term debt, net

   4,929,542    

Total unitholders’ capital

   4,027,418    
  

 

 

   

 

 

 

Total capitalization

  $8,956,960    $   
  

 

 

   

 

 

 

  Pro Forma                      
  Year Ended
December 31,

2018
  Three Months
Ended March 31,
  Year Ended December 31, 
 2019  2018  2018  2017(1)  2016  2015  2014 (2) 
  (Unaudited)  (Unaudited)        (Unaudited) 
  (In thousands, except per share data) 

Statement of Operations Data:

        

Revenues(3):

        

Oil

 $275,239  $60,571  $63,692  $275,239  $76,876  $30,565  $3,972  $65 

Natural gas

  76,056   21,781   16,890   76,056   49,211   16,093   1,055   115 

Natural gas liquids

  88,472   16,187   20,388   88,472   40,298   8,307   658   26 

Gain (loss) on derivative contracts

  78,054   (83,642  (9,614  78,054   (6,797  —     —     —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total revenues

  517,821   14,897   91,356   517,821   159,588   54,965   5,685   206 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Operating Expenses(3):

        

Production expenses

  47,600   14,846   8,355   47,600   16,872   5,090   549   83 

Gathering, transportation and processing

  —     —     —     —     18,602   5,920   273   6 

Production taxes

  17,579   5,039   2,386   17,579   3,685   1,087   190   12 

Exploration expenses

  43,303   12,488   7,850   43,303   32,629   5,258   121   24 

Depreciation, depletion, amortization and accretion

  123,922   41,572   21,865   123,922   37,376   24,996   2,091   66 

General and administrative

  56,297   15,825   14,020   60,874   31,357   5,581   2,074   344 

Gain on sale of assets

  —     (644  —     —     (838  —     —     —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total operating expenses

  288,701   89,106   54,476   293,278   139,683   47,932   5,298   535 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Operating income (loss)

  229,120   (74,209  36,880   224,543   19,905   7,033   387   (329

Other income (expense):

        

Interest expense

  (8,352  (6,744  (1,799  (8,352  (1,461  (86  —     —   

Other income

  —     —     —     —     13   —     4   2 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total other income (expense)

  (8,352  (6,744  (1,799  (8,352  (1,448  (86  4   2 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Income tax expense(4)

  56,296   (22,897  —     356,862   —     —     —     —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net income (loss)

 $164,472  $(58,056 $35,081  $(140,671 $18,457  $6,947  $391  $(327
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net income (loss) per share:

        

Basic and diluted

 $1.08  $(0.38 $0.23  $(0.92    

Weighted average shares outstanding:

        

Basic and diluted

  152,540   152,540   151,294   152,232     

Balance Sheet Data (at period end):

        

Total assets

  $2,791,436   $2,749,109  $1,885,592  $363,083  $113,053  $16,618 

Total liabilities

  $1,351,393   $1,254,075  $300,823  $88,836  $14,761  $1,492 

Total equity

  $1,440,043   $1,495,034  $1,584,769  $274,247  $98,292  $15,126 

Other Financial Data:

        

Adjusted EBITDAX(5)

 $299,342  $72,757  $73,986  $299,342  $96,711  $37,287  $2,603  $(237

Net Debt(5)

  $600,450   $507,756  $83,868  $13,147   NM   NM 

 

(1)As of                     , 2012, LINN had cash

On August 31, 2017, Old Linn contributed certain oil and cash equivalents of approximately $        million.natural gas assets to Roan LLC. The revenue and operating expenses associated with these assets for the period from contribution through December 31, 2017 is included in our results for the year ended December 31, 2017.

(2)As

Includes financial information from July 1, 2014 to December 31, 2014. Citizen, the predecessor of , 2012, LINN had total borrowings of approximately $        outstanding under its Credit Facility.Roan LLC, was formed on July 1, 2014.

(3)

Revenue and operating expenses for the three months ended March 31, 2019 and 2018 and the year ended December 31, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

(4)

The pro forma data reflects pro forma tax expense based on the statutory tax rate of 25.5% at December 31, 2018 to prospective periods. As described under “Reorganization,” Roan Inc. was formed in conjunction with the Reorganization. Roan Inc. is taxable as a corporation under the Code, and as a result, is subject to U.S. federal, state and local income taxes. Our predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for federal income tax purposes, were deemed to pass to the members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of the members. The pro forma data excludes the income tax expense associated with the initial deferred tax liability recognized as a result of the Reorganization. The initial recording of the deferred tax liability has been reflected in the historical financial statements, but is not included in the pro forma data due to its non-recurring nature.

(5)

Adjusted EBITDAX and Net Debt arenon-GAAP financial measures. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss) and a reconciliation of Net Debt to long-term debt, please see“Summary—Non-GAAP Financial Measure.”

Index to Financial Statements

OUR DIVIDEND POLICYMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In addition to theThe following discussion of our dividend policy, pleaseand analysis should be read “Forward-Looking Statements”in conjunction with the “Selected Historical and “Risk Factors” for information regarding statements that do not relate strictly to historical or current factsUnaudited Pro Forma Financial Data” and certain risks inherent in LINN’s business and our shares. For additional information regarding the historical operating results of LINN, you should refer to the historicalaccompanying financial statements of LINN included elsewhere in this prospectus.

Our Dividend Policy

Within five business days after we receive a distribution on our LINN units, we will pay dividends on our shares of the cash we receive as distributions in respect of our LINN units, net of reserves for income taxes payable by us. If distributions are made on the LINN units other than in cash, we will pay a dividend on our shares in substantially the same form, provided that if LINN makes a distribution on the LINN units in the form of additional LINN units, we would distribute an equal number of additional shares to our shareholders, such that, immediately following such distributions, the number of our shares outstanding is equal to the number of LINN units we hold.

Because we have elected to be treated as a corporation for U.S. federal income tax purposes, we are obligated to pay U.S. federal income tax on the net income allocated to us by LINN with respect to the LINN units we own, and we may be subject to a 20% alternative minimum tax on our alternative minimum taxable income to the extent that the alternative minimum tax exceeds our regular income tax. Please read “Material U.S. Federal Income Tax Consequences—LinnCo U.S. Federal Income Taxation.” We are also classified as a corporation in most states in which LINN does business for state income tax purposes and will be subject to state income tax at rates that vary from state to state on the net income allocated to us by LINN with respect to the LINN units we own.

The reserves for income taxes payable by us will account for the U.S. federal income taxes, any alternative minimum taxes, and the state income taxes described in the preceding paragraph. We have estimated that for each of the periods ending December 31, 2012, 2013, 2014 and 2015 the amount of such taxes (and, therefore, the amount of such reserves) will not exceed an amount equal to     % of the cash we receive as distributions in respect of our LINN units.

This estimate is based on a number of assumptions that may prove incorrect. Events inconsistent with our assumptions that could cause our tax liabilities to be substantially higher than estimated (and, therefore, cause our reserves for taxes to be higher than estimated and dividends on our shares to be lower than estimated) include:

a significant decrease in drilling activity by LINN;

an issuance of significant additional units by LINN without a corresponding increase in the aggregate tax deductions generated by LINN;

alternative minimum tax provisions;

the enactment of proposed legislation that would eliminate the current deduction of intangible drilling costs and other tax incentives to the oil and natural gas industry; or

a significant increase in oil and natural gas prices.

Please read “Risk Factors—We may incur substantial corporate income tax liabilities on income allocated to us by LINN with respect to LINN units we own, in which case the quarterly dividend of cash you receive per share would be substantially less than the quarterly per unit distribution of cash that we receive from LINN.”

LINN’s Distribution Policy

LINN will make quarterly distributions to its unitholders of all “available cash.”

Index to Financial Statements

“Available cash” means, for each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash reserves established by the LINN board of directors to:

provide for the proper conduct of business (including reserves for future capital expenditures, future debt service requirements and anticipated credit needs); and

comply with applicable laws, debt instruments or other agreements;

plusall cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are borrowings that will be made under LINN’s credit facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders.

LINN’s Historical Distributions

The following sets forth LINN’s historical distributions for the years ended December 31, 2011 and 2010 and for the three months ended March 31, 2012. Distributions declared during each quarter are presented.

Quarter

  

Cash

Distributions

Declared

Per Unit

 

2012 (1)

  

January 1 – March 31

  $0.69  

2011:

  

October 1 – December 31

  $0.69  

July 1 – September 30

  $0.69  

April 1 – June 30

  $0.66  

January 1 – March 31

  $0.66  

2010:

  

October 1 – December 31

  $0.66  

July 1 – September 30

  $0.63  

April 1 – June 30

  $0.63  

January 1 – March 31

  $0.63  

(1)On April 24, 2012, LINN declared a cash distribution of $0.725 per unit, which was paid on May 15, 2012 to unitholders of record at the close of business May 8, 2012.

Index to Financial Statements

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA OF LINN

The following table shows summary historical financial and operating data of LINN as of the dates and for the periods indicated. The selected historical financial data presented for the years ended December 31, 2007 and 2008 are derived from LINN’s historical audited financial statements. The selected historical financial data presented as of December 31, 2009, 2010 and 2011 and for the years ended December 31, 2009, 2010 and 2011 are derived from the historical audited financial statements that are included elsewhere in this prospectus. The selected historical financial data of LINN presented as of March 31, 2012 and for the three months ended March 31, 2011 and 2012 are derived from the unaudited historical financial statements that arerelated notes included elsewhere in this prospectus. The following table shoulddiscussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be read together with,outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and is qualified in its entirety by reference to, the historicalnatural gas, production volumes, estimates of proved reserves, capital expenditures, economic and unaudited financial statementscompetitive conditions, regulatory changes and the accompanying notes includedother uncertainties, as well as those factors discussed below and elsewhere in this prospectus. The table should also be read together with “Management’s Discussionprospectus, particularly in “Risk Factors” and Analysis“Cautionary Statement Regarding Forward-Looking Statements,” all of Financial Conditionwhich are difficult to predict. In light of these risks, uncertainties and Results of Operations.”assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Because of rapid growth through acquisitionsOverview

We are an independent oil and natural gas company focused on the development of properties, LINN’s historicalour assets throughout the eastern and southern Anadarko Basin. The Anadarko Basin, which spans from south-central Oklahoma to the northeast corner of the Texas panhandle, is one of the largest and most prolific onshore oil and natural gas basins in the United States, featuring multiple producing horizons and extensive well production history demonstrated over seven decades of development. We focus our development on formations where we believe we can apply our technical and operational expertise in order to increase production and cash flow. Our objective is to maximize shareholder value and corporate returns by generating steady production growth, strongpre-tax margins and significant cash flow.

Through December 31, 2018, we and our predecessors have drilled 214 gross (72 net) wells in the Merge, SCOOP and STACK plays. Our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs, and provides us development opportunities through multiple stacked prospective development horizons. We believe these development horizons have been substantiallyde-risked through the development of more than 400 horizontal wells since early 2014, of which 152 were drilled by us or our predecessors, and over 4,450 vertical wells drilled in our development area, as well as associated subsurface data, including well cores and logs and3-D seismic and the consistent geology surrounding our position. As of December 31, 2018, we operated 163 gross (131 net) horizontal producing wells and had an interest in an additional 317 gross (19 net) horizontal producing wells.

Market Conditions

The oil and natural gas industry is cyclical and commodity prices are highly volatile. Beginning in the second half of 2014, oil and natural gas prices began a rapid and significant decline as global supply exceeded demand. This oversupply continued through the first half of 2016 and led to troughs in oil and natural gas prices, which at the lowest NYMEX prices were $27.45 per Bbl and $1.64 per MMBtu, respectively. Oil and natural gas prices began to recover and reached levels as high as $76.41 per Bbl and $4.84 per MMBtu, respectively, during the year ended December 31, 2018, but started to decline again towards the end of 2018 and into early 2019, reaching levels as low as $61.59 per Bbl and $2.46 per MMBtu during April 2019. We expect that these markets will continue to be volatile in the future. Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production, including NGLs that are extracted from our natural gas during processing. A decline in commodity prices may adversely affect our business, financial condition or results of operations and period-to-period comparisons of these resultsour ability to meet our capital expenditure obligations and certain other financial datacommitments. Please see “Risk Factors— Risks Related to Our Business—Oil, natural gas and NGL prices are volatile. A decline in commodity prices may not be meaningfuladversely affect our business, financial condition or indicative of future results. The results of LINN’s Appalachian Basinoperations and Mid Atlantic Well Service, Inc.our ability to meet our capital expenditure obligations and financial commitments.”

Lower commodity prices not only reduce our revenue and cash flows, but also may limit the amount of oil, natural gas and NGL reserves that we can develop economically and therefore potentially lower our reserves. Lower commodity prices in the future could also result in impairments of our properties. The occurrence of any of the foregoing could materially and adversely affect our future business, financial condition, results of operations, which were disposedoperating cash flows, liquidity or ability to finance planned capital expenditures. Alternatively, commodity prices may increase and such derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.

Drilling Activity

We took over as operator in May 2018 of the oil and natural gas properties contributed to us by Citizen and Old Linn. Our core development area is located across approximately 170,000 acres in 2008,the Merge, SCOOP and STACK plays within the Anadarko Basin. As of December 31, 2018, we operated 591 gross wells and had an interest in an additional 672 gross wells throughout our area of operations. In the first quarter of 2019, we reduced our rig count to four rigs across all of our properties.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

actual and projected reserve and production levels;

realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;

lease operating expenses; and

capital expenditures on our oil and natural gas properties.

Please see “—Sources of Revenue,” “—Production Volumes,” “—Principal Components of Our Cost Structure” and “—Adjusted EBITDAX” for a discussion on these metrics.

Sources of Revenue

Our revenues are classifiedderived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. Under our major gas dedication agreements, we have the ability to elect ethane recovery or rejection on a monthly basis. An election of ethane recovery typically results in higher NGL volumes and lower realized NGL prices while ethane rejection typically results in lower NGL volumes and higher realized NGL prices. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as discontinued operations, due to post-closing adjustments,a result of changes in volumes of production sold or changes in commodity prices. The following table presents the sources of our revenues, excluding the effects of derivative contracts, for the years ended December 31, 2007 through December 31, 2009. Unless otherwise indicated, results of operations information presented herein relates only to continuing operations.presented:

 

  At or for the Year Ended December 31,  At or for the Three
Months Ended
March 31,
 
  2007  2008  2009  2010  2011  2011  2012 
     (Unaudited) 
  (in thousands, except per unit amounts) 

Statement of operations data:

       

Oil, natural gas and natural gas liquids sales

 $255,927   $755,644   $408,219   $690,054   $1,162,037   $240,707   $348,895  

Gains (losses) on oil and natural gas derivatives

  (345,537  662,782    (141,374  75,211    449,940    (369,476  2,031  

Depreciation, depletion and amortization

  69,081    194,093    201,782    238,532    334,084    66,366    117,276  

Interest expense, net of amounts capitalized

  38,974    94,517    92,701    193,510    259,725    63,464    77,519  

Income (loss) from continuing operations

  (356,194  825,657    (295,841  (114,288  438,439    (446,682  (6,202

Income (loss) from discontinued operations, net of taxes(1)

  (8,155  173,959    (2,351  —      —      —      —    

Net income (loss)

  (364,349  999,616    (298,192  (114,288  438,439    (446,682  (6,202

Income (loss) per unit—continuing operations:

       

Basic

  (5.17  7.18    (2.48  (0.80  2.52    (2.75  (0.04

Diluted

  (5.17  7.18    (2.48  (0.80  2.51    (2.75  (0.04

Income (loss) per unit—discontinued operations:

       

Basic

  (0.12  1.52    (0.02  —      —      —      —    

Diluted

  (0.12  1.52    (0.02  —      —      —      —    

Net income (loss) per unit:

       

Basic

  (5.29  8.70    (2.50  (0.80  2.52    (2.75  (0.04

Diluted

  (5.29  8.70    (2.50  (0.80  2.51    (2.75  (0.04

Distributions declared per unit

  2.18    2.52    2.52    2.55    2.70    0.66    0.69  

Weighted average basic units outstanding

  68,916    114,140    119,307    142,535    172,004    163,107    193,256  

Index to Financial Statements
  At or for the Year Ended December 31,  At or for the Three
Months Ended
March 31,
 
  2007  2008  2009  2010  2011  2011  2012 
     (Unaudited) 
  (in thousands, except per unit amounts) 

Cash flow data:

       

Net cash provided by (used in):

       

Operating activities(2)

 $(44,814 $179,515   $426,804   $270,918   $518,706   $107,966   $35,513  

Investing activities

  (2,892,420  (35,550  (282,273  (1,581,408  (2,130,360  (358,068  (1,460,555

Financing activities

  2,932,080    (116,738  (150,968  1,524,260    1,376,767    209,425    1,448,112  

Balance sheet data:

       

Total assets

 $3,807,703   $4,722,020   $4,340,256   $5,933,148   $8,000,137    $9,577,092  

Long-term debt

  1,443,830    1,653,568    1,588,831    2,742,902    3,993,657     4,929,542  

Unitholders’ capital

  2,026,641    2,760,686    2,452,004    2,788,216    3,428,910     4,027,418  
   Three Months Ended
March 31,
  Years Ended December 31, 
   2019  2018  2018  2017  2016 

Revenues

      

Oil sales(1)

   61  63  63  46  56

Natural gas sales(1)

   22  17  17  30  29

Natural gas liquid sales(1)

   17  20  20  24  15

 

(1)Includes gains (losses) on sale of assets, net of taxes.
(2)Includes premiums paid for derivatives of approximately, $279 million, $130 million, $94 million, $120 million and $134 million and for the years ended December 31, 2007, 2008, 2009, 2010 and 2011, respectively, and approximately $178 million

Revenue for the three months ended March 31, 2012.2019 and 2018 and the year ended December 31, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that

were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

Realized Prices on the Sales of Oil, Natural Gas and NGLs Volumes

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, natural gas and NGLs, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. The following table presents summary unaudited operating data with respect to our production and sales ofaverage oil and natural gas forprices were higher during the periods presented and summary information with respect to LINN’s estimated proved oil and natural gas reserves at year-end. DeGolyer and MacNaughton, independent petroleum engineers, provided the estimates of LINN’s proved oil and natural gas reserves as ofyear ended December 31, 2007, 2008, 2009, 2010 and 2011 set forth below.

  At or for the Year Ended
December 31,
  At or for the Three
Months Ended
March 31
 
  2007  2008  2009  2010  2011          2011                  2012         

Production data:

       

Average daily production—continuing operations:

       

Natural gas (MMcf/d)

  51    124    125    137    175    158    229  

Oil (MBbls/d)

  3.4    8.6    9.0    13.1    21.5    17.2    26.1  

NGL (MBbls/d)

  2.7    6.2    6.5    8.3    10.8    8.6    14.2  

Total (MMcfe/d)

  87    212    218    265    369    312    471  

Average daily production—discontinued operations:

       

Total (MMcfe/d)

  24    12    —      —      —      —      —    

Estimated proved reserves—continuing operations:(1)

       

Natural gas (Bcf)

  833    851    774    1,233    1,675    

Oil (MMBbls)

  55    84    102    156    189    

NGL (MMBbls)

  43    51    54    71    94    

Total (Bcfe)

  1,419    1,660    1,712    2,597    3,370    

Estimated proved reserves—discontinued operations:(1)

       

Total (Bcfe)

  197    —      —      —      —      

(1)In accordance with SEC regulations, reserves at December 31, 2009, December 31, 2010, and December 31, 2011, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In accordance with SEC regulations, reserves for all prior years were estimated using year-end prices. The price used to estimate reserves is held constant over the life of the reserves.

Index to Financial Statements

2018 measured against the year ended 2017. The following table sets forth certain information with respect to LINN’s Pro Forma Proved Reserves atour average oil and natural gas prices received on the oil, natural gas and NGL production sold for the years ended December 31, 20112018, 2017 and average daily production for2016 and the three months ended March 31, 2012:2019 and 2018:

 

Region

  Pro Forma Proved
Reserves (Bcfe)(1)
   % Oil and NGL  % Proved
Developed
  Average Daily Production
For The Three Months
Ended March 31, 2012

(MMcfe/d)
 

Mid-Continent

   1,884     41  53  273  

Hugoton Basin(2)

   1,081     47  87  39  

Green River Basin(3)

   753     27  56    

Permian Basin

   527     79  56  89  

Michigan/Illinois

   317     4  91  36  

California

   193     93  93  13  

Williston/Powder River Basin(2)

   189     92  63  21  

East Texas(4)

   110     3  100    
  

 

 

   

 

 

  

 

 

  

 

 

 

Total

   5,054     45  66  471  
  

 

 

   

 

 

  

 

 

  

 

 

 
   Three Months Ended
March 31,
   Year Ended December 31, 
   2019   2018       2018           2017           2016     

Average prices(1):

          

Oil (per Bbl)

  $53.18   $61.36   $63.07   $52.87   $41.36 

Natural gas (per Mcf)

  $1.87   $1.90   $1.82   $2.80   $2.52 

NGLs (per Bbl)

  $12.18   $23.33   $19.27   $26.44   $15.21 

Total realized price per Boe

  $22.37   $29.72   $27.59   $28.16   $23.40 

Average realized prices after effects of derivative settlements(1)(2):

          

Oil (per Bbl)

  $59.46   $56.78   $55.87   $53.57   $41.36 

Natural gas (per Mcf)

  $1.53   $1.92   $1.73   $2.89   $2.52 

NGLs (per Bbl)

  $13.86   $23.33   $19.60   $26.44   $15.21 

Total realized price per Boe

  $23.59   $28.39   $25.50   $28.60   $23.40 

 

(1)Except as otherwise noted, proved reserves

Average prices for the legacy oilthree months ended March 31, 2019 and natural gas assets were calculated on2018 and the year ended December 31, 2011,2018 reflects the reserve report date,adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and usetransportation expenses to be accounted for as a pricededuction from revenue. We elected the modified retrospective method of $4.12/MMBtu for natural gastransition. Accordingly, comparative information has not been adjusted and $95.84/Bbl for oil, which representcontinues to be reported under the unweighted average of the first-day-of-the-month prices for each of the twelve months immediately preceding December 31, 2011.previous revenue standard.

(2)Pro forma proved reserves for the Hugoton Acquisition (in the Hugoton Basin region) and the Anadarko Joint Venture (in the Williston/Powder River Basin region) were calculated using a price

Excludes settlement of $3.73/MMBtu for natural gas and $98.02/Bbl for oil, which represent the unweighted average of the first-day-of-the-month prices for each of the twelve months ending March 1, 2012, the most recent twelve-month periodderivative contracts prior to the closing of each of those transactions. The proved reserves for the Anadarko Joint Venture were based on LINN’s preliminary internal evaluation.their contractual maturity.

(3)Pro forma proved reserves for the Jonah Acquisition (in the Green River Basin region) were calculated using a price of $3.15/MMBtu for natural gas and $95.63/Bbl for oil, which represents the unweighted average of the first-day-of-the-month prices for each of the twelve months ending June 1, 2012, the most recent twelve-month period prior to the closing of the Jonah Acquisition. The proved reserves for the Jonah Acquisition were based on LINN’s preliminary internal evaluation of information provided by the seller.
(4)Pro forma proved reserves for the East Texas Acquisition were calculated using a price of $3.54/MMBtu for natural gas and $97.65/Bbl for oil, which represent the unweighted average of the first-day-of-the-month prices for each of the twelve months ending April 1, 2012, the most recent twelve-month period prior to the closing of the East Texas Acquisition.

Pricing for certain of our natural gas contracts are based on Oklahoma indexes, including ONEOK Gas Transportation (OGT), Panhandle Eastern Pipeline (PEPL) and Southern Star Central Gas Pipeline (SSCGP) due to the proximity of those pipelines to our producing properties. These indexes fluctuate from Henry Hub pricing due to a variety of reasons including the distance to the retail market, availability and capacity of pipelines to move the product to distribution hubs, customer demand, and competition between suppliers.

Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OFProduction Volumes

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion analyzestable presents historical production volumes for our properties for the financial conditionyears ended December 31, 2018, 2017 and results2016:

   Three Months Ended
March 31,
   Year Ended December 31, 
       2019           2018           2018           2017           2016     

Total sales volumes:

          

Oil (MBbls)

   1,139    1,038    4,364    1,454    739 

Natural gas (MMcf)

   11,620    8,912    41,890    17,582    6,382 

NGLs (MBbls)

   1,329    874    4,592    1,524    546 

Total (MBoe)

   4,405    3,397    15,938    5,908    2,349 

Average daily total volumes (MBoe)

   48.9    37.7    43.7    16.2    6.3 

As reservoir pressures decline, production volumes from a given well or formation decreases and production expenses may increase. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of operationsproduction. Our ability to increase reserves through development projects and acquisitions is dependent on many factors, including infrastructure capacity in our areas of usoperation, our ability to raise capital, our ability to obtain regulatory approvals, and LINN. The historical financial statementsour ability to successfully identify and consummate acquisitions. Please see “—Critical Accounting Policies and Estimates” for further discussion.

Derivative Contracts Activity

Our primary market risk exposure is in the unaudited interim financial statements included in this prospectus reflect the assets, liabilitiesprice we receive for our oil, natural gas, and operations of LINN. You should read the following discussionNGLs production. Pricing for oil, natural gas and analysis of financial conditionNGLs production has been volatile and results of operations of us and LINN in conjunction with the historical financial statements, the unaudited interim financial statements, and the notes thereto, included elsewhere in this prospectus.

LinnCo

We are a recently formed limited liability company that has elected to be treated as a corporationunpredictable for U.S. federal income tax purposes.

Our Business

We will use all of the proceeds from this offering to purchase a number of units representing limited liability company interests in LINN equal to the number of our shares sold in this offering,several years, and we will have no assets or operations other than those relatedexpect this volatility to our ownership of LINN units. Our limited liability company agreement requires that we maintain a one-to-one ratio between the number of our shares outstanding and the number of LINN units we own.

Liquidity and Capital Resources

Our authorized capital structure consists of two classes of shares: (1) common shares with indirect voting rights in LINN, which are the shares being issued in this offering and (2) voting shares, 100% of which are currently held by LINN. At                     , 2012, our issued capitalization consisted of $1,000 contributed by LINN in connection with our formation and in exchange for its voting share.

LINN has agreed to pay on our behalf all legal, accounting, tax advisory, financial advisory and engineering fees, printing costs or other administrative and out-of-pocket expenses we incur, along with any other expenses incurred in connection with this offering or incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and other reports to holders of our shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, independent auditor fees and registrar and transfer agent fees. In addition, LINN will also agree to indemnify us for damages suffered or costs incurred (other than income taxes payable by us) in connection with carrying out our activities, as described in “Certain Relationships and Related Transactions—Our Relationship with LINN Energy, LLC—Omnibus Agreement.”

If we issue additional sharescontinue in the future, we will immediately use the net proceeds from those sales to purchase a number of additional LINN units equal to the number of shares sold in such offering. Accordingly, we do not anticipate any other sources of or needs for additional liquidity. We are not permitted to borrow money or incur debt without the prior approval of holders owning a majority of our outstanding shares.

Results of Operations

Upon completion of our initial offering of shares to the public and the purchase of LINN units, our results of operations will consist of our equity in earnings of LINN. When this offering is completed, we will own approximately     % of all of LINN’s outstanding units (assuming no exercise of the underwriters’ option to purchase additional shares). See “Risk Factors—Risks Inherent in an Investment in LinnCo—LINN may issue additional units or other classes of units, and we may issue additional shares without your approval, which would dilute our direct and your indirect ownership interest in LINN and your ownership interest in us.”

Index to Financial Statements

LINN

Executive Overview

LINN’s mission is to acquire, develop and maximizefuture. To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from a growing portfolio of long-lifetime to time we enter into derivative arrangements for our oil and natural gas assets. LINN is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering in January 2006. LINN’s properties are currently located in eight operating regions in the U.S.:

Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays);

Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle;

Green River Basin, which includes properties located in southwest Wyoming;

Permian Basin, which includes areas in west Texas and southeast New Mexico;

Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;

California, which includes the Brea Olinda Field of the Los Angeles Basin;

Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming; and

East Texas, which includes properties in east Texas.

Results for the year ended December 31, 2011, included the following:

oil, natural gas and NGL sales of approximately $1.2 billion comparedproduction. Our hedging instruments allow us to $690 million in 2010;

average daily production of 369 MMcfe/d compared to 265 MMcfe/d in 2010;

realized gains on commodity derivatives of approximately $257 million compared to $308 million in 2010;

adjusted EBITDA of approximately $998 million compared to $732 million in 2010;

adjusted net income of approximately $313 million compared to $219 million in 2010;

capital expenditures, excluding acquisitions, of approximately $697 million compared to $263 million in 2010; and

294 wells drilled (292 successful) compared to 139 wells drilled (138 successful) in 2010.

Results for the three months ended March 31, 2012, included the following:

oil, natural gas and NGL sales of approximately $349 million compared to $241 million for the first quarter of 2011;

average daily production of 471 MMcfe/d compared to 312 MMcfe/d for the first quarter of 2011;

realized gains on commodity derivatives of approximately $55 million compared to $56 million for the first quarter of 2011;

adjusted EBITDA of approximately $302 million compared to $210 million for the first quarter of 2011;

adjusted net income of approximately $48 million compared to $62 million for the first quarter of 2011;

capital expenditures, excluding acquisitions, of approximately $259 million compared to $113 million for the first quarter of 2011; and

81 wells drilled (79 successful) compared to 46 wells drilled (44 successful) for the first quarter of 2011.

Index to Financial Statements

Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze LINN’s performance. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and LINN’s ability to sustain or increase distributions. The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives, and depreciation, depletion and amortization. Adjusted net income is used by LINN’s management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, impairment of long-lived assets, loss on extinguishment of debt and (gains) losses on sale of assets, net.See “Non-GAAP Financial Measures” for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Joint Venture

On April 3, 2012, LINN entered into a joint venture agreement with an affiliate of Anadarko whereby LINN will participate as a partner in the CO2-enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming. Anadarko assigned LINN 23% of its interest in the field in exchange for future funding by LINN of $400 million of Anadarko’s development costs. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the agreement date.

Acquisitions

On June 21, 2012, LINN entered into a purchase agreement for certain oil and natural gas properties located in the Green River Basin area of southwest Wyoming for a contract price of approximately $1.025 billion. LINN anticipates the acquisition will close on or before July 31, 2012, and will be financed with the proceeds from borrowings under its revolving credit facility. In addition to customary closing conditions, the acquisition is subject to a preferential right of purchase that encompasses substantially all of the properties. The expiry period for waiver or acceptance of the preferential right of purchase is anticipated during the first week of July 2012. The pending acquisition includes approximately 753 Bcfe of estimated proved reserves. The estimated proved reserves for the Jonah Acquisition were based on LINN’s preliminary internal evaluation of information provided by the seller.

On May 1, 2012, LINN completed the acquisition of certain oil and natural gas properties located in east Texas for total consideration of approximately $168 million. The acquisition included approximately 110 Bcfe of proved reserves as of the acquisition date.

On March 30, 2012, LINN completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin area of southwestern Kansas for total consideration of approximately $1.17 billion. The acquisition included approximately 701 Bcfe of proved reserves as of the acquisition date.

During the first quarter of 2012, LINN completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. LINN, in the aggregate, paid approximately $63 million in total consideration for these properties.

On December 15, 2011, LINN completed the acquisition of certain oil and natural gas properties located primarily in the Granite Wash of Texas and Oklahoma from Plains Exploration & Production Company (“Plains”) for total consideration of approximately $544 million. The acquisition included approximately 51 MMBoe (306 Bcfe) of proved reserves as of the acquisition date.

On November 1, 2011, and November 18, 2011, LINN completed two acquisitions of certain oil and natural gas properties located in the Permian Basin for total consideration of approximately $110 million. The acquisitions included approximately 7 MMBoe (42 Bcfe) of proved reserves as of the acquisition dates.

On June 1, 2011, LINN completed the acquisition of certain oil and natural gas properties in the Cleveland play, located in the Texas Panhandle, from Panther Energy Company, LLC and Red Willow Mid-Continent, LLC

Index to Financial Statements

(collectively referred to as “Panther”) for total consideration of approximately $223 million. The acquisition included approximately 9 MMBoe (54 Bcfe) of proved reserves as of the acquisition date.

On May 2, 2011, and May 11, 2011, LINN completed two acquisitions of certain oil and natural gas properties located in the Williston Basin for total consideration of approximately $153 million. The acquisitions included approximately 6 MMBoe (35 Bcfe) of proved reserves as of the acquisition dates.

On April 1, 2011, and April 5, 2011, LINN completed two acquisitions of certain oil and natural gas properties located in the Permian Basin for total consideration of approximately $239 million. The acquisitions included approximately 13 MMBoe (79 Bcfe) of proved reserves as of the acquisition dates.

On March 31, 2011, LINN completed the acquisition of certain oil and natural gas properties located in the Williston Basin from an affiliate of Concho Resources Inc. (“Concho”) for total consideration of approximately $194 million. The acquisition included approximately 8 MMBoe (50 Bcfe) of proved reserves as of the acquisition date.

During 2011, LINN completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. LINN, in the aggregate, paid approximately $38 million in total consideration for these properties.

Proved reserves as of the acquisition date for all of the above referenced acquisitions were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.

Commodity Derivatives

LINN hedges a significant portion of its forecasted production to reduce, exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to pay distributions, service debt and manage its business. By removing a significant portion of the price volatility associated with future production, LINN expects to mitigate, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in commodity prices.

During the year ended December 31, 2011, LINN entered into commodity derivative contracts consisting of oil and natural gas swapsprices and provide increased certainty of cash flows. These derivatives are not designated as a hedging instrument for certain years through 2016hedge accounting under GAAP and oil trade month roll swapsas such, gains or losses resulting from the change in fair value along with the gains or losses resulting in settlement of derivative contracts are reflected as gain or loss on derivative contracts included in the statement of operations. Please see “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for October 2011 through December 2015. In September 2011, LINN canceled itsfurther discussion.

We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices. However, in times of low commodity prices, our ability to enter into additional commodity derivative contracts with favorable commodity price terms may be limited, which may adversely impact our future revenues and cash flows as compared to historical periods during which we were able to hedge our oil and natural gas swapsproduction at higher prices.

Our hedging strategy and future hedging transactions will be determined primarily at our discretion and may differ from historical hedging activity. Further, under our credit facility, we are prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the year 2016thirty (30) month period following the date of any hedging transaction and used(b) 80% of reasonably anticipated projected production from proved reserves for the realized gainssecond thirty (30) month period following the date of approximately $27 millionany hedging transaction. If the amount of borrowings outstanding exceeds 50% of the borrowing base, we are required to increase pricesenter into and maintain on its existinga quarterly basis hedge transactions permitted by the credit facility with respect to not less than 50% of reasonably anticipated quarterly production volumes for oil and natural gas swapsfrom proved developed reserves for the year 2012.next eight quarters following the most recent quarter end. As of March 31, 2019 and December 31, 2018, we were in compliance with these requirements under our credit facility.

There are a variety of hedging strategies and instruments used to hedge future price risk. We utilize fixed price swaps and basis swaps to manage the price risk associated with forecasted sale of our oil and natural gas production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential. When the referenced settlement price is less than the price specified in the contract, we receive an amount from the counterparty based on the price difference multiplied by the volume. When the referenced settlement price exceeds the price specified in the contract, we pay the counterparty an amount based on the price difference multiplied by the volume.

For more information on our open positions executed as of March 31, 2019, please see “—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

We expect to continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at the discretion of our board of directors and may be different than our historical hedging practices.

Principal Components of Our Cost Structure

Production expenses.Production expenses are the costs incurred in the operation and maintenance of producing properties. Expenses for compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our production expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as compression and salt water disposal associated with completion water, are variable and increase or decrease as hydrocarbon production levels and the volume of completion water disposal increases or decreases. For example, as production rates and associated completion water flowback decrease over time, we optimize compression horsepower and decrease our completion water disposal costs.

We monitor our well performance and associated operating costs to determine if any wells or properties should be shut in, recompleted or sold. One measure by which we evaluate operating costs is production expenses per Boe. This per unit measure also allows us to monitor these costs to identify trends and to benchmark against other producers. Although we strive to reduce our production expenses, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties. For example, we may increase field level expenditures to optimize our operations, incurring higher expenses in one quarter relative to another, or we may acquire or dispose of properties that have different production expenses per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing production expenses on aperiod-to-period basis.

Gathering, transportation and processing.Prior to adoption of ASC 606, gathering, transportation and processing expenses principally consist of expenditures to prepare and gather production from the wellhead, gas processing costs and transportation to a specified sales point. These costs are mainly driven by increases or decreases in unprocessed natural gas production volumes. As a result of the adoption of ASC 606 in 2018, these costs are accounted for as a deduction from revenue in the 2018 and 2019 periods.

Production taxes.Production taxes are paid on produced oil, natural gas and NGLs based on apercentage of revenues at fixed rates established by federal, state or local taxing authorities. In September 2011, LINN also paid premiumsgeneral, theproduction taxes we pay correlate to changes in our oil, natural gas and NGL revenues. As all of approximately $33 millionour oil andnatural gas production is in the state of Oklahoma, we are generally subject to increase prices on its existing oil putsa tax rate of 2% for the years 2012first 36months of production and 2013. In addition, during7% thereafter for wells spud on or after July 1, 2015. Starting with July 2018 production, the fourth quartertax rate increased to 5% for the first 36 months of 2011, LINN paid premiumsproduction and 7% thereafter. We are also subject to ad valoremtaxes in the

counties where our production is located. Ad valorem taxes are generally based on the valuation ofour oil and natural gas properties, which also trend with oil and natural gas prices and vary across the differentcounties in which we operate.

Exploration expenses These are primarily geological and geophysical costs that include seismic survey costs, amortization of approximately $52 millionthe costs of unproved properties assessed for put optionsimpairment on a group basis, costs of carrying and approximately $22 millionretaining unproved properties, and costs related to unsuccessful leasing efforts.

Depreciation, depletion, amortizationand accretion. Depreciation, depletion and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units of production method. Please see “—Critical Accounting Policies and Estimates—Oil and Natural Gas Properties” for further discussion.

Accretion expense relates to our asset retirement obligations (“ARO”). We record the fair value of the legal liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the asset’s inception, with the offsetting increase pricesto property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Please see “—Critical Accounting Policies and Estimates” for further discussion.

General and administrative. General and administrative (“G&A”) costs include corporate overhead such as payroll and benefits for our corporate staff, equity-based compensation cost, office rent for our headquarters, audit and other fees for professional services and legal compliance. G&A expenses are reported net of recoveries from other owners in properties operated by us and amounts capitalized pursuant to the successful efforts method. We expect that we will incur additional general and administrative expenses as a result of being a publicly-traded company.

Adjusted EBITDAX

Adjusted EBITDAX is a supplementalnon-GAAP financial measure that is used by management and other users of our financial statements. We define Adjusted EBITDAX as net income (loss) adjusted for interest expense, depreciation, depletion, amortization and accretion, income tax expense, exploration costs,non-cash equity-based compensation expense, gain on early termination of derivative contracts,non-cash (gain) loss on derivative contracts, reorganization transaction costs, expense for allowance for doubtful accounts and gain on sale of assets. Please see “Summary Historical and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measure—Adjusted EBITDAX and Net Debt” for a discussion on this metric. Our predecessor, Roan LLC, passed through its existing oil putstaxable income to its owners for 2012income tax purposes and, 2013.thus, we have not incurred historical income tax expenses.

DuringFactors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Corporate Reorganization

On September 24, 2018, we completed the Reorganization where Roan LLC, our accounting predecessor, became a wholly-owned subsidiary of Roan Inc. Roan Inc. was incorporated in September 2018 to serve as a holding company and, prior to the Reorganization, had no previous operations, assets or liabilities. For more information on our Reorganization and the ownership of our Class A common stock by our principal stockholders, please see “Prospectus Summary—Recent Developments—History and Reorganization” and “Principal and Selling Stockholders” and the unaudited pro forma financial statements included elsewhere in this prospectus.

The historical financial statements included elsewhere in this prospectus (i) on and after September 24, 2018, are that of Roan, Inc., and (ii) prior to September 24, 2018, are that of Roan LLC, our predecessor. The

historical financial and operational information of Roan LLC presented in this prospectus, (i) prior to August 31, 2017, the date of the completion of the Contribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the historical financial and operational information of Citizen prior to August 31, 2017 does not include financial information relating to the Linn Contributed Business. The pro forma financial information presented in this prospectus treats the Reorganization as if the Reorganization happened on January 1, 2018. As a result, the historical financial data and pro forma financial information presented in this prospectus may not give you an accurate indication of what our actual results would have been if our Reorganization had been completed at the beginning of the periods presented.

Public Company Expenses

Subsequent to the Reorganization, we incur direct, incremental G&A expenses as a result of becoming a publicly traded company, including but not limited to, costs associated with hiring new personnel, Sarbanes-Oxley compliance, implementation of compensation programs that are competitive with our public company peer group, costs associated with annual and quarterly reports and our other filings with the SEC, exchange listing fees, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental G&A expenses are not included in our historical results of operations.

Income Taxes

As a result of the Reorganization, we became subject to federal and state tax. Due to the change in tax status, we have recorded a tax provision for the initial recording of the deferred tax liability recognized as a result of the Reorganization. Our accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of its members.

Impact of ASC Topic 606 Adoption

Revenue for the three months ended March 31, 2012, LINN entered into commodity derivative contracts consisting2019 and 2018 and the year ended December 31, 2018 reflects the adoption of oilASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and natural gas swapstransportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and puts for April 2012 through December 2016, and paid premiums for put options of approximately $178 million. Also duringcontinues to be reported under the three months ended March 31, 2012, LINN entered into natural gas basis swaps for April 2012 through December 2016.

Index to Financial Statements

In April 2012, LINN entered into commodity derivative contracts consisting of oil and natural gas swaps for 2016 and 2017, oil puts for 2014 through 2016, and natural gas puts for 2016 and 2017, and paid premiums for put options of approximately $231 million. In May 2012, LINN entered into commodity derivative contracts consisting of oil swaps for July 2012 through December 2012, and oil trade month roll swaps for July 2012 through December 2017. LINN also intends to enter into additional derivatives contracts in connection with the Jonah Acquisition. The following table summarizes derivative positions for the periods indicated as of May 31, 2012.

  June 1 –
December 31,
2012
  2013  2014  2015  2016  2017 

Natural gas positions:

      

Fixed price swaps:

      

Hedged volume (MMMBtu)

  43,399    81,815    90,904    99,937    106,250    106,945  

Average price ($/MMBtu)

 $5.39   $5.31   $5.35   $5.43   $4.25   $4.31  

Puts:(1)

      

Hedged volume (MMMBtu)

  39,132    64,298    56,998    58,714    63,093    51,465  

Average price ($/MMBtu)

 $5.47   $5.49   $5.00   $5.00   $5.00   $5.00  

Total:

      

Hedged volume (MMMBtu)

  82,531    146,113    147,902    158,651    169,343    158,410  

Average price ($/MMBtu)

 $5.43   $5.39   $5.21   $5.27   $4.53   $4.53  

Oil positions:

      

Fixed price swaps:(2)

      

Hedged volume (MBbls)

  5,138    9,523    9,523    10,070    10,376    3,650  

Average price ($/Bbl)

 $97.69   $98.19   $95.67   $98.38   $91.43   $91.04  

Puts:

      

Hedged volume (MBbls)

  1,356    2,440    3,287    2,993    2,965    —    

Average price ($/Bbl)

 $100.00   $100.00   $91.56   $90.00   $90.00   $—    

Total:

      

Hedged volume (MBbls)

  6,494    11,963    12,810    13,063    13,341    3,650  

Average price ($/Bbl)

 $98.17   $98.56   $94.61   $96.46   $91.11   $91.04  

Natural gas basis differential positions:(3)

      

Panhandle basis swaps:

      

Hedged volume (MMMBtu)

  43,717    77,800    79,388    87,162    19,764    —    

Hedged differential ($/MMBtu)

 $(0.56 $(0.56 $(0.33 $(0.33 $(0.31 $—    

MichCon basis swaps:

      

Hedged volume (MMMBtu)

  5,692    9,600    9,490    9,344    —      —    

Hedged differential ($/MMBtu)

 $0.12   $0.10   $0.08   $0.06   $—     $—    

Houston Ship Channel basis swaps:

      

Hedged volume (MMMBtu)

  3,659    5,731    5,256    4,891    4,575    —    

Hedged differential ($/MMBtu)

 $(0.10 $(0.10 $(0.10 $(0.10 $(0.10 $—    

Permian basis swaps:

      

Hedged volume (MMMBtu)

  2,654    4,636    4,891    5,074    —      —    

Hedged differential ($/MMBtu)

 $(0.19 $(0.20 $(0.21 $(0.21 $—     $—    

Oil timing differential positions:

      

Trade month roll swaps:(4)

      

Hedged volume (MBbls)

  3,803    6,944    7,254    7,251    7,446    6,486  

Hedged differential ($/Bbl)

 $0.21   $0.22   $0.22   $0.24   $0.25   $0.25  

(1)Includes certain outstanding natural gas puts of approximately 6,197 MMMBtu for the period June 1, 2012, through December 31, 2012, 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.

Index to Financial Statements
(2)Includes certain outstanding fixed price oil swaps on 14,750 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
(3)Settle on the respective pricing index to hedge basis differential associated with natural gas production.
(4)LINN hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, LINN generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

Operating Regions

Following isprevious revenue standard. For a discussion of LINN’s six operating regions used during the years ending December 31, 2009, 2010 and 2011. Priorimpact of the adoption of ASC 606 on the Company’s current period results as compared to January 1, 2012, LINN’s properties were divided into these six operating regions in the United States:

Mid-Continent Deep

The Mid-Continent Deep region includes properties inprevious revenue recognition standards, see Note 3 to the Deep Granite Wash formation in the Texas Panhandle, which produces at depths ranging from 10,000 feet to 16,000 feet, as well as properties in Oklahoma and Kansas, which produce at depths of more than 8,000 feet. Mid-Continent Deep proved reserves represented approximately 47% of total proved reserves at December 31, 2011, of which 49% were classified as proved developed reserves. This region produced 172 MMcfe/d or 47% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $268 million to drillaudited consolidated financial statements included elsewhere in this region. During 2012, LINN anticipates spending approximately 65% of its total oil and natural gas capital budget for development activities in the Mid-Continent Deep region, primarily in the Deep Granite Wash formation.prospectus.

To more efficiently transport its natural gas in the Mid-Continent Deep region to market, LINN owns and operates a network of natural gas gathering systems comprised of approximately 285 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the Texas Panhandle.

Mid-Continent Shallow

The Mid-Continent Shallow region includes properties producing from the Brown Dolomite formation in the Texas Panhandle, which produces at depths of approximately 3,200 feet, as well as properties in Oklahoma, Louisiana and Illinois, which produce at depths of less than 8,000 feet. Mid-Continent Shallow proved reserves represented approximately 20% of total proved reserves at December 31, 2011, of which 70% were classified as proved developed reserves. This region produced 63 MMcfe/d or 17% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $9 million to drill in this region. During 2012, LINN anticipates spending approximately 2% of its total oil and natural gas capital budget for development activities in the Mid-Continent Shallow region.

To more efficiently transport its natural gas in the Mid-Continent Shallow region to market, LINN owns and operates a network of natural gas gathering systems comprised of approximately 665 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the Texas Panhandle.

Index to Financial Statements

Permian Basin

The Permian Basin is one of the largest and most prolific oil and natural gas basins in the U.S. LINN’s properties are located in West Texas and Southeast New Mexico and produce at depths ranging from 2,000 feet to 12,000 feet. Permian Basin proved reserves represented approximately 16% of total proved reserves at December 31, 2011, of which 56% were classified as proved developed reserves. This region produced 73 MMcfe/d or 20% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $255 million to drill in this region. During 2012, LINN anticipates spending approximately 25% of its total oil and natural gas capital budget for development activities in the Permian Basin region, primarily in the Wolfberry trend.

Michigan

The Michigan region includes properties producing from the Antrim Shale formation in the northern part of the state, which produces at depths ranging from 600 feet to 2,200 feet. Michigan proved reserves represented approximately 9% of total proved reserves at December 31, 2011, of which 90% were classified as proved developed reserves. This region produced 35 MMcfe/d or 9% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $3 million to drill in this region. During 2012, LINN anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the Michigan region.

California

The California region consists of the Brea Olinda Field of the Los Angeles Basin. The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths ranging from 1,000 feet to 7,500 feet. California proved reserves represented approximately 6% of total proved reserves at December 31, 2011, of which 93% were classified as proved developed reserves. This region produced 14 MMcfe/d or 4% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $6 million to drill in this region. During 2012, LINN anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the California region.

Williston Basin

The Williston Basin is one of the premier oil basins in the U.S. LINN’s properties are located in North Dakota and produce at depths ranging from 9,000 feet to 12,000 feet. Williston Basin proved reserves represented approximately 2% of total proved reserves at December 31, 2011, of which 48% were classified as proved developed reserves. This region produced 12 MMcfe/d or 3% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $39 million to drill in this region. During 2012, LINN anticipates spending approximately 6% of its total oil and natural gas capital budget for development activities in the Williston Basin region.

During 2012, LINN realigned its operating regions and now allocates its properties among eight operating regions in the U.S.:

Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays);

Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle;

Green River Basin, which was added in June 2012 for the pending Jonah Acquisition and includes properties located in southwest Wyoming;

Permian Basin, which includes areas in west Texas and southeast New Mexico;

Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;

California, which includes the Brea Olinda Field of the Los Angeles Basin;

Williston/Powder River Basin, which includes the Bakken formation in North Dakota; and

East Texas, which was added in May 2012 and includes properties located in east Texas.

Index to Financial Statements

Historical Results of Operations and Operating Expenses

Three Months Ended March 31, 2012,2019 Compared to Three Months Ended March 31, 20112018

The following table presents selected financial and operating information for the periods presented.

 

   Three Months Ended
March 31,
    
   2011  2012  Variance 
   (in thousands) 

Revenues and other:

    

Natural gas sales

  $66,798   $65,785   $(1,013

Oil sales

   138,638    231,165    92,527  

NGL sales

   35,271    51,945    16,674  
  

 

 

  

 

 

  

 

 

 

Total oil, natural gas and NGL sales

   240,707    348,895    108,188  

Gains (losses) on oil and natural gas derivatives

   (369,476  2,031    371,507  

Marketing and other revenues

   2,296    3,164    868  
  

 

 

  

 

 

  

 

 

 
   (126,473  354,090    480,563  
  

 

 

  

 

 

  

 

 

 

Expenses:

    

Lease operating expenses

   45,901    71,636    25,735  

Transportation expenses

   5,855    10,562    4,707  

Marketing expenses

   809    692    (117

General and administrative expenses(1)

   30,560    43,321    12,761  

Exploration costs

   445    410    (35

Depreciation, depletion and amortization

   66,366    117,276    50,910  

Taxes, other than income taxes

   15,727    25,195    9,468  

Losses on sale of assets and other, net

   576    1,494    918  
  

 

 

  

 

 

  

 

 

 
   166,239    270,586    104,347  
  

 

 

  

 

 

  

 

 

 

Other income and (expenses)

   (149,772  (80,788  68,984  
  

 

 

  

 

 

  

 

 

 

Income (loss) before income taxes

   (442,484  2,716    445,200  

Income tax expense

   (4,198  (8,918  (4,720
  

 

 

  

 

 

  

 

 

 

Net loss

  $(446,682 $(6,202 $440,480  
  

 

 

  

 

 

  

 

 

 

Adjusted EBITDA(2)

  $209,996   $302,139   $92,143  
  

 

 

  

 

 

  

 

 

 

Adjusted net income(2)

  $62,307   $48,422   $(13,885
  

 

 

  

 

 

  

 

 

 
   Three Months Ended
March 31,
 
   2019   2018 

Production Data

    

Oil (MBbls)

   1,139    1,038 

Natural gas (MMcf)

   11,620    8,912 

Natural gas liquids (MBbls)

   1,329    874 

Total volumes (MBoe)

   4,405    3,397 

Average daily total volumes (MBoe/d)

   48.9    37.7 

Average Prices—as reported

    

Oil (per Bbl)

  $53.18   $  61.36 

Natural gas (per Mcf)

  $1.87   $1.90 

Natural gas liquids (per Bbl)

  $12.18   $23.33 

Total (per Boe)

  $22.37   $29.72 

Average Prices—including impact of derivative contract settlements(1)

    

Oil (per Bbl)

  $59.46   $56.78 

Natural gas (per Mcf)

  $1.53   $1.92 

Natural gas liquids (per Bbl)

  $13.86   $23.33 

Total (per Boe)

  $23.59   $28.39 

Average Prices—excluding gathering, transportation and processing costs(2)

    

Oil (per Bbl)

  $53.27   $61.36 

Natural gas (per Mcf)

  $2.50   $2.39 

Natural gas liquids (per Bbl)

  $16.31   $28.66 

Total (per Boe)

  $25.30   $32.40 

 

(1)

Excludes settlement of derivative contracts prior to their contractual maturity for the three months ended March 31, 2018.

(2)

Excludes the effects of netting gathering, transportation and processing costs.

Revenues

Our operating revenues includes revenues from the sale of oil, natural gas and NGLs and loss on our derivative contracts. The following table provides information on our operating revenues:

   Three Months Ended
March 31,
 
   2019   2018 
   (in thousands) 

Revenues

    

Oil sales

  $60,571   $63,692 

Natural gas sales

   21,781    16,890 

Natural gas liquid sales

   16,187    20,388 

Loss on derivative contracts

   (83,642   (9,614
  

 

 

   

 

 

 

Total revenues

  $14,897   $91,356 
  

 

 

   

 

 

 

Oil sales. Our oil sales decreased by approximately $3.1 million, or 5%, to $60.6 million for the three months ended March 31, 2019 from $63.7 million for the three months ended March 31, 2018. This decrease was primarily due to the decrease in average sales prices received for produced volumes. The decrease in average sales prices received on our oil production for the three months ended March 31, 2019 reflects the decrease in the index price for oil in the 2019 period as compared to the 2018 period.

Natural Gas sales. Our natural gas sales increased by approximately $4.9 million, or 29%, to $21.8 million for the three months ended March 31, 2019 from $16.9 million for the three months ended March 31, 2018. This increase was primarily due to the increase in production. Our natural gas production increased 2,708 MMcf, or 30%, to 11,620 MMcf for the three months ended March 31, 2019 from 8,912 MMcf for the three months ended March 31, 2018. The increase in production volumes was due to drilling activity during 2018 and the first quarter of 2019.

NGL sales. Our NGL sales decreased by approximately $4.2 million, or 21%, to $16.2 million for the three months ended March 31, 2019 from $20.4 million for the three months ended March 31, 2018. This decrease was primarily due to the decrease in the average sales prices received for produced volumes partially offset by an increase in production. Our NGL production increased 455 MBbls, or 52%, to 1,329 MBbls for the three months ended March 31, 2019 from 874 MBbls for the three months ended March 31, 2018. The increase in production volumes was due to drilling activity during 2018 and the first quarter of 2019. The decrease in average sales prices received on our NGL production for the three months ended March 31, 2019 reflects the decrease in the prices received for NGLs in the 2019 period as compared to the 2018 period.

Loss on derivative contracts. For the three months ended March 31, 2019, we had a loss on derivative contracts of $83.6 million compared with a loss on derivative contracts of $9.6 million for the three months ended March 31, 2018. For the three months ended March 31, 2019 our loss on derivative contracts included an unfavorable change in the fair value of derivative contracts of $89.0 million partially offset by a gain on settlement of derivatives contracts of $5.4 million. For the three months ended March 31, 2018, our loss on derivative contracts included unfavorable change in the fair value of derivative contracts of $5.5 million and a loss on settlement of derivative contracts of $4.1 million. The $4.1 million loss on settlement of derivative contracts included a gain of $0.4 million related to the settlement of derivative contracts prior to their contractual maturity. This increase in the unfavorable change in the fair value of derivative contracts was related to changes in the future price outlook for oil prices that had a negative impact on the fair value of our derivative contracts. This was offset by settlements received during 2019 for oil derivative contracts due to favorable pricing compared to payments made during 2018 for oil derivative contracts due to unfavorable pricing.

Operating Expenses

Our operating expenses reflect costs incurred in the development, production and sale of oil, natural gas and NGLs. The following table provides information on our operating expenses:

   Three Months Ended
March 31,
 
   2019   2018 
   (in thousands, except costs per Boe) 

Operating Expenses

    

Production expenses

  $14,846   $8,355 

Production taxes

   5,039    2,386 

Exploration expenses

   12,488    7,850 

Depreciation, depletion, amortization and accretion

   41,572    21,865 

General and administrative (1)

   15,825    14,020 

Gain on sale of other assets

   (664   —   
  

 

 

   

 

 

 

Total

  $89,106   $54,476 
  

 

 

   

 

 

 

Average Costs per Boe

    

Production expenses

  $3.37   $2.46 

Production taxes

   1.14    0.70 

Exploration expenses

   2.84    2.31 

Depreciation, depletion, amortization and accretion

   9.44    6.44 

General and administrative (1)

   3.59    4.13 

Gain on sale of other assets

   (0.15   —   
  

 

 

   

 

 

 

Total

  $20.23   $16.04 
  

 

 

   

 

 

 

(1)

General and administrative expenses for the three months ended March 31, 2011,2019 and March 31, 2012,2018 include approximately $5$3.1 million, or $0.70 per Boe, and $8$2.3 million, respectively,or $0.67 per Boe, of noncash unit-basedequity-based compensation expenses.

(2)This is a non-GAAP measure used by management to analyze LINN’s performance. See “—Non-GAAP Financial Measures” for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Index to Financial Statements
   Three Months Ended
March 31,
     
   2011   2012   Variance 

Average daily production:

      

Natural gas (MMcf/d)

   158     229     45

Oil (MBbls/d)

   17.2     26.1     52

NGL (MBbls/d)

   8.6     14.2     65

Total (MMcfe/d)

   312     471     51

Weighted average prices (hedged):(1)

      

Natural gas (Mcf)

  $8.99    $6.33     (30)% 

Oil (Bbl)

  $86.24    $92.80     8

NGL (Bbl)

  $45.81    $40.21     (12)% 

Weighted average prices (unhedged):(2)

      

Natural gas (Mcf)

  $4.71    $3.16     (33)% 

Oil (Bbl)

  $89.44    $97.25     9

NGL (Bbl)

  $45.81    $40.21     (12)% 

Average NYMEX prices:

      

Natural gas (MMBtu)

  $4.13    $2.74     (34)% 

Oil (Bbl)

  $94.10    $102.93     9

Costs per Mcfe of production:

      

Lease operating expenses

  $1.63    $1.67     2

Transportation expenses

  $0.21    $0.25     19

General and administrative expenses(3)

  $1.09    $1.01     (7)% 

Depreciation, depletion and amortization

  $2.36    $2.74     16

Taxes, other than income taxes

  $0.56    $0.59     5

(1)Includes the effect of realized gains on derivatives of approximately $56 million and $55 million for the three months ended March 31, 2011, and March 31, 2012,expense, respectively.
(2)Does not include the effect of realized gains (losses) on derivatives.
(3)General and administrative expenses for the three months ended March 31, 2011, and March 31, 2012, include approximately $52019 includes $1.5 million, and $8 million, respectively,or $0.34 per Boe, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the three months ended March 31, 2011, and March 31, 2012, were $0.90 per Mcfe and $0.83 per Mcfe, respectively. This is a non-GAAP measure used by LINN’s management to analyze LINN’s performance.bad debt expense.

RevenuesProduction expenses. Production expenses are the operating costs incurred to maintain production. Such costs include the cost of saltwater disposal, monitoring, pumping, chemicals, maintenance, repairs, workover expenses and Otherdirect labor and overhead related to production activities. Production expenses were $14.8 million, or $3.37 per Boe, for the three months ended March 31, 2019, which was an increase of $6.5 million, or 78%, from $8.4 million, or $2.46 per Boe, for the three months ended March 31, 2018. The increase in production expenses during 2019 compared to 2018 was due to increased production and increases in water hauling and disposal costs and surface repairs incurred during the three months ended March 31, 2019.

Production taxes

Oil, Natural Gas and NGL Sales

Oil,. Production taxes are paid on produced oil, natural gas, and NGLNGLs based primarily on a percentage of sales increased approximately $108 millionrevenues from production sold at fixed rates established by federal, state or 45% to approximately $349local taxing authorities. Production taxes were $5.0 million for the three months ended March 31, 2012,2019, an increase of $2.7 million, or 111%, from approximately $241$2.4 million for the three months ended March 31, 2011,2018. Production taxes primarily increased due to higherincreased production volumestax rates, which became effective in July 2018.

Exploration expenses. These are primarily geological and higher oil prices partially offset by lower natural gasgeophysical costs that include seismic survey costs, amortization of the costs of unproved properties assessed for impairment on a group basis, costs of carrying and NGL prices. Higher oil prices resulted in an increase in revenues of approximately $19 million. Lower natural gasretaining unproved properties, and NGL prices resulted in a decrease in revenues of approximately $32costs related to unsuccessful leasing efforts. Exploration expenses were $12.5 million and $7 million, respectively.

Average daily production volumes increased to 471 MMcfe/d duringfor the three months ended March 31, 2012,2019, an increase of $4.6 million, or 59%, from 312 MMcfe/d during$7.9 million for the three months ended March 31, 2011. Higher oil, natural gas2018. Exploration expenses for both periods primarily consisted of unproved leasehold amortization. Unproved leasehold amortization is calculated by considering our

drilling plans and NGL production volumes resultedthe lease terms of our existing unproved properties. The increase in unproved leasehold amortization for the 2019 period is primarily due to additional leasehold set to expire.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $41.6 million, or $9.44 per Boe, for the three months ended March 31, 2019, compared to $21.9 million, or $6.44 per Boe, for the three months ended March 31, 2018, which is an increase of $19.7 million or 90%. The increase in depreciation, depletion, amortization and accretion was primarily due to an increase in revenues of approximately $73 million, $31 million and $24 million, respectively.

Index to Financial Statements

The following sets forth average daily production by region:

   Three Months Ended
March  31,
        
   2011   2012   Variance 

Average daily production (MMcfe/d):

       

Mid-Continent

   165     273     108    65

Permian Basin

   58     89     31    53

Hugoton Basin

   39     39     —      1

Michigan/Illinois

   36     36     —      —    

Williston/Powder River Basin

   —       21     21    —    

California

   14     13     (1  (4)% 
  

 

 

   

 

 

   

 

 

  
   312     471     159    51
  

 

 

   

 

 

   

 

 

  

The 65% increase in average daily production volumes in the Mid-Continent region primarily reflects LINN’s 2011 and 2012 capital drilling programs in the Granite Wash formation, as well as the impact of the acquisition in the Cleveland horizontal play in June 2011 and the Plains acquisition in December 2011. Average daily production volumes in the Permian Basin region reflect the impact of acquisitions in 2011 and subsequent development capital spending. The Hugoton Basin, Michigan/Illinois and California regions consist of low-decline asset bases and continue to produce at consistent levels. Average daily production volumes in the Williston/Powder River Basin region reflect the impact of acquisitions in 2011.

Gains (Losses) on Oil and Natural Gas Derivatives

LINN determines the fair value of itsdepletion rate for our oil and natural gas derivatives utilizing pricing models that useproperties and to a varietylesser extent, increased production. The per Boe increase in the depletion rate is attributable to higher capital expenditures.

General and administrative. General and administrative expenses were $15.8 million, or $3.59 per Boe, for the three months ended March 31, 2019, an increase of techniques, including market quotes and pricing analysis.$1.8 million or 13% from $14.0 million, or $4.13 per Boe, for the three months ended March 31, 2018. During the three months ended March 31, 2012, LINN had commodity derivative contracts for approximately 114%2019, general and administrative expenses included salaries and benefits of its natural gas production$8.7 million, equity-based compensation expense of $3.1 million and 108%bad debt expense of its oil production, which resulted in realized gains of approximately $55$1.5 million. During the three months ended March 31, 2011, LINN had commodity derivative contracts2018, general and administrative expenses included salaries and benefits of $2.2 million, equity-based compensation expense of $2.3 million and fees paid to Citizen and Linn under the MSAs of $7.5 million. The MSAs with Citizen and Linn concluded in April 2018.

Other Expenses

Interest expense, net. Interest expense, net of capitalized interest, for approximately 113% of its natural gas production and 117% of its oil production, which resulted in realized gains of approximately $56 million. Unrealized gains and losses result from changes in market valuations of derivativesthe three months ended March 31, 2019 was $6.7 million as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, unrealized losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, unrealized gains are recognized. During the first quarter of 2012, expected future oil prices increased resulting in unrealized losses of approximately $199 million, and natural gas prices decreased resulting in unrealized gains of approximately $146 million, for net unrealized losses on derivatives of approximately $53$1.8 million for the three months ended March 31, 2012. During the first quarter of 2011, expected future oil and natural gas prices2018. This increase was due to increased which resulted in net unrealized losses on derivatives of approximately $425 million forborrowings outstanding during the three months ended March 31, 2011.

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such2019 as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $26 million or 56% to approximately $72 million for the three months ended March 31, 2012, from approximately $46 million for the three months ended March 31, 2011. Lease operating expenses per Mcfe also increased to $1.67 per Mcfe for the three months ended March 31, 2012, from $1.63 per Mcfe for the three months ended March 31, 2011. Lease operating expenses increased primarily due to costs associated with properties acquired during 2011.

Index to Financial Statements

Transportation Expenses

Transportation expenses increased by approximately $5 million or 80% to approximately $11 million for the three months ended March 31, 2012, from approximately $6 million for the three months ended March 31, 2011, primarily due to higher production volumes.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $12 million or 42% to approximately $43 million for the three months ended March 31, 2012, from approximately $31 million for the three months ended March 31, 2011. The increase was primarily due to an increase in acquisition integration expenses of approximately $6 million, an increase in salaries and benefits expense of approximately $3 million, driven primarily by increased employee headcount, and an increase in unit-based compensation expense of approximately $2 million. General and administrative expenses per Mcfe decreased to $1.01 per Mcfe for the three months ended March 31, 2012, from $1.09 per Mcfe for the three months ended March 31, 2011, due to higher production volumes.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $51 million or 77% to approximately $117 million for the three months ended March 31, 2012, from approximately $66 million for the three months ended March 31, 2011. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe also increased to $2.74 per Mcfe for the three months ended March 31, 2012, from $2.36 per Mcfe for the three months ended March 31, 2011, primarily due to higher production volumes in operating areas with higher rates.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $9 million or 60% to approximately $25 million for the three months ended March 31, 2012, from approximately $16 million for the three months ended March 31, 2011. Severance taxes, which are a function of revenues generated from production, increased approximately $5 million compared to the three months ended March 31, 2011, primarily due to higher production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $4 million compared to the three months ended March 31, 2011, primarily due to property acquisitions in 2011.2018.

Other Income and (Expenses)tax benefit

   Three Months Ended
March 31,
    
   2011  2012  Variance 
   (in thousands) 

Loss on extinguishment of debt

  $(84,562 $—     $84,562  

Interest expense, net of amounts capitalized

   (63,464  (77,519  (14,055

Other, net

   (1,746  (3,269  (1,523
  

 

 

  

 

 

  

 

 

 
  $(149,772 $(80,788 $68,984  
  

 

 

  

 

 

  

 

 

 

Other. The income and (expenses) decreased by approximately $69 milliontax benefit for the three months ended March 31, 2012, compared2019 was $22.9 million and is the result of our effective tax rate applied to the three months ended March 31, 2011. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees associated with the May 2019

Index to Financial Statements

Senior Notes and the November 2019 Senior Notes, as defined in Note 6 to LINN’s historical audited financial statementsour net loss for the year ended December 31, 2011, included elsewhere in this prospectus. For the three months ended March 31, 2011, LINN recordedquarter. As Roan LLC was a loss on extinguishment of debt of approximately $85 million as a result of the redemptions of and cash tender offersflow-through entity for a portion of the Original Senior Notes, as defined in Note 6. See “Debt” in “Liquidity and Capital Resources” below for additional details.

Income Tax Expense

LINN is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of LINN passed through to unitholders. Limited liability companies are subject to Texas margin tax. Limited liability companies were also subject to state income taxes in Michigan during the three months ended March 31, 2011. In addition, certain of LINN’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. LINN recognizedthere was no income tax expense of approximately $9 millionor benefit recorded for the three months ended March 31, 2012, compared to approximately $4 million for the three months ended March 31, 2011. Income tax expense increased primarily due to higher income from LINN’s taxable subsidiaries during the three months ended March 31, 2012, compared to the same period in 2011.2018.

Net Loss

Net loss decreased by approximately $441 million or 99% to approximately $6 million for the three months ended March 31, 2012, from approximately $447 million for the three months ended March 31, 2011. The decrease was primarily due to higher production revenues and higher gains on oil and natural gas derivatives, partially offset by higher expenses, including interest. The three months ended March 31, 2011 also included a loss on extinguishment of debt; there was no comparable amount reported for the three months ended March 31, 2012. See discussions above for explanations of variances.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $92 million or 44% to approximately $302 million for the three months ended March 31, 2012, from approximately $210 million for the three months ended March 31, 2011. The increase was primarily due to higher production revenues resulting from higher production volumes and higher oil prices, partially offset by higher expenses and lower natural gas and NGL prices. See “—Non-GAAP Financial Measures” for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP. See discussions above for explanations of variances.

Adjusted Net Income

Adjusted net income decreased by approximately $14 million or 22% to approximately $48 million for the three months ended March 31, 2012, from approximately $62 million for the three months ended March 31, 2011. The decrease was primarily due to higher expenses, including interest, partially offset by higher production revenues. See discussions above for explanations of variances.

Index to Financial Statements

Year Ended December 31, 2011,2018 Compared to Year Ended December 31, 20102017

 

   Year Ended December 31,    
   2010  2011  Variance 
   (in thousands) 

Revenues and other:

    

Natural gas sales

  $211,596   $278,714   $67,118  

Oil sales

   359,996    714,385    354,389  

NGL sales

   118,462    168,938    50,476  
  

 

 

  

 

 

  

 

 

 

Total oil, natural gas and NGL sales

   690,054    1,162,037    471,983  

Gains on oil and natural gas derivatives(1)

   75,211    449,940    374,729  

Marketing and other revenues

   7,015    10,477    3,462  
  

 

 

  

 

 

  

 

 

 
   772,280    1,622,454    850,174  
  

 

 

  

 

 

  

 

 

 

Expenses:

    

Lease operating expenses

   158,382    232,619    74,237  

Transportation expenses

   19,594    28,358    8,764  

Marketing expenses

   2,716    3,681    965  

General and administrative expenses(2)

   99,078    133,272    34,194  

Exploration costs

   5,168    2,390    (2,778

Depreciation, depletion and amortization

   238,532    334,084    95,552  

Impairment of long-lived assets

   38,600    —      (38,600

Taxes, other than income taxes

   45,182    78,522    33,340  

Losses on sale of assets and other, net

   6,490    3,494    (2,996
  

 

 

  

 

 

  

 

 

 
   613,742    816,420    202,678  
  

 

 

  

 

 

  

 

 

 

Other income and (expenses)

   (268,585  (362,129  (93,544
  

 

 

  

 

 

  

 

 

 

Income (loss) before income taxes

   (110,047  443,905    553,952  

Income tax expense

   (4,241  (5,466  (1,225
  

 

 

  

 

 

  

 

 

 

Net Income (loss)

  $(114,288 $438,439   $552,727  
  

 

 

  

 

 

  

 

 

 

Adjusted EBITDA(3)

  $732,131   $997,621   $265,490  
  

 

 

  

 

 

  

 

 

 

Adjusted net income(3)

  $219,489   $313,331   $93,842  
  

 

 

  

 

 

  

 

 

 
   Year Ended
December 31,
 
   2018   2017 

Production Data

    

Oil (MBbls)

   4,364    1,454 

Natural gas (MMcf)

   41,890    17,582 

Natural gas liquids (MBbls)

   4,592    1,524 

Total volumes (MBoe)

   15,938    5,908 

Average daily total volumes (MBoe/d)

   43.7    16.2 

Average Prices—as reported(1)

    

Oil (per Bbl)

  $63.07   $52.87 

Natural gas (per Mcf)

  $1.82   $2.80 

Natural gas liquids (per Bbl)

  $19.27   $26.44 

Total (per Boe)

  $27.59   $28.16 

Average Prices—including impact of derivative contract settlements(1)

    

Oil (per Bbl)

  $55.87   $53.57 

Natural gas (per Mcf)

  $1.73   $2.89 

Natural gas liquids (per Bbl)

  $19.60   $26.44 

Total (per Boe)

  $25.50   $28.60 

Average Prices—excluding gathering, transportation and processing costs(2)

    

Oil (per Bbl)

  $63.11   $52.87 

Natural gas (per Mcf)

  $2.29   $2.80 

Natural gas liquids (per Bbl)

  $24.83   $26.44 

Total (per Boe)

  $30.46   $28.16 

 

(1)During

Average prices for the year ended December 31, 2011, LINN canceled (before2018 reflects the contract settlement date) derivative contractsadoption of ASC 606 on estimated future oilJanuary 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and natural gas production resulting in realized gainstransportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of approximately $27 million.transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

(2)General

Excludes the effects of netting gathering, transportation and administrative expenses for the years ended December 31, 2010, and December 31, 2011, include approximately $13 million and $21 million, respectively, of noncash unit-based compensation expenses.processing costs under ASC 606.

(3)This is a non-GAAP measure used by management to analyze LINN’s performance. See “Non-GAAP Financial Measures” for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Revenues

Index to Financial Statements
   Year Ended December 31,     
       2010           2011       Variance 

Average daily production:

      

Natural gas (MMcf/d)

   137     175     28

Oil (MBbls/d)

   13.1     21.5     64

NGL (MBbls/d)

   8.3     10.8     30

Total (MMcfe/d)

   265     369     39

Weighted average prices (hedged):(1)

      

Natural gas (Mcf)

  $8.52    $8.20     (4)% 

Oil (Bbl)

  $94.71    $89.21     (6)% 

NGL (Bbl)

  $39.14    $42.88     10

Weighted average prices (unhedged):(2)

      

Natural gas (Mcf)

  $4.24    $4.35     3

Oil (Bbl)

  $75.16    $91.24     21

NGL (Bbl)

  $39.14    $42.88     10

Average NYMEX prices:

      

Natural gas (MMBtu)

  $4.40    $4.05     (8)% 

Oil (Bbl)

  $79.53    $95.12     20

Costs per Mcfe of production:

      

Lease operating expenses

  $1.64    $1.73     5

Transportation expenses

  $0.20    $0.21     5

General and administrative expenses(3)

  $1.02    $0.99     (3)% 

Depreciation, depletion and amortization

  $2.46    $2.48     1

Taxes, other than income taxes

  $0.47    $0.58     23
The following table provides information on our operating revenues:

   Year Ended
December 31,
 
   2018   2017 
   (in thousands) 

Revenues

    

Oil sales(1)

  $275,239   $76,876 

Natural gas sales(1)

   76,056    49,211 

Natural gas liquid sales(1)

   88,472    40,298 

Gain (loss) on derivative contracts

   78,054    (6,797
  

 

 

   

 

 

 

Total revenues

  $517,821   $159,588 
  

 

 

   

 

 

 

 

(1)Includes the effect of realized gains on derivatives of approximately $308 million and $230 million (excluding $27 million realized gains on canceled contracts)

Revenue for the yearsyear ended December 31, 2010,2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and December 31, 2011, respectively.

(2)Doestransportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not includebeen adjusted and continues to be reported under the effect of realized gains (losses) on derivatives.
(3)General and administrative expenses for the years ended December 31, 2010, and December 31, 2011, include approximately $13 million and $21 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the years ended December 31, 2010, and December 31, 2011, were $0.88 per Mcfe and $0.83 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze LINN’s performance.previous revenue standard.

Revenues and Other

Oil Natural Gas and NGL Salessales.

Oil, natural gas and NGL Our oil sales increased by approximately $472$198.4 million, or 68%258%, to approximately $1.2 billion for the year ended December 31, 2011, from approximately $690$275.2 million for the year ended December 31, 2010, due to higher commodity prices and higher production volumes. Higher oil, NGL and natural gas prices resulted in an increase in revenues of approximately $126 million, $15 million and $7 million, respectively.

Average daily production volumes increased to 369 MMcfe/d during the year ended December 31, 2011,2018 from 265 MMcfe/d during the year ended December 31, 2010. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $228 million, $60 million and $36 million, respectively.

Index to Financial Statements

The following sets forth average daily production by region, as established by LINN during 2011 and 2010:

   Year Ended December 31,        
   2010   2011   Variance 

Average daily production (MMcfe/d):

       

Mid-Continent Deep

   133     172     39    30

Mid-Continent Shallow

   66     63     (3  (5)% 

Permian Basin

   31     73     42    134

Michigan

   21     35     14    67

California

   14     14     —      —    

Williston Basin

   —       12     12    —    
  

 

 

   

 

 

   

 

 

  
   265     369     104    39
  

 

 

   

 

 

   

 

 

  

The 30% increase in average daily production volumes in the Mid-Continent Deep region is primarily due to LINN’s 2010 and 2011 capital drilling programs in the Deep Granite Wash formation, as well as the impact of the acquisition in the Cleveland Play in June 2011. The 5% decrease in average daily production volumes in the Mid-Continent Shallow region reflects downtime related to weather and third-party plant maintenance, and the effects of natural declines, partially offset by the results of LINN’s drilling and optimization programs. The 134% increase in average daily production volumes in the Permian Basin region reflects the impact of acquisitions in 2010 and 2011 and subsequent development capital spending. The 67% increase in average daily production volumes in the Michigan region reflects the full year impact of acquisitions in the second and fourth quarters of 2010. The California region consists of a low-decline asset base and continues to produce at a consistent level. Average daily production volumes in the Williston Basin region reflect the impact of LINN’s acquisitions in this region in 2011.

Gains (Losses) on Oil and Natural Gas Derivatives

LINN determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. During the year ended December 31, 2011, LINN had commodity derivative contracts for approximately 101% of its natural gas production and 101% of its oil production, which resulted in realized gains of approximately $257 million (including realized gains on canceled contracts of approximately $27 million). During the year ended December 31, 2010, LINN had commodity derivative contracts for approximately 114% of its natural gas production and 97% of its oil production, which resulted in realized gains of approximately $308 million. Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, unrealized losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, unrealized gains are recognized. During 2011, expected future oil and natural gas prices decreased, which resulted in net unrealized gains on derivatives of approximately $193$76.9 million for the year ended December 31, 2011. During 2010, expected future2017. This increase was primarily due to the increase in production as well as the increase in average sales prices received for our produced volumes. Our oil pricesproduction increased 2,910 MBbls, or 200%, to 4,364 MBbls for the year ended December 31, 2018 from 1,454 MBbls for the year ended December 31, 2017. The increase in production volumes was due to production associated with oil and expected future natural gas properties contributed by Old Linn in August 2017 and drilling activity in the fourth quarter of 2017 and throughout 2018. The increase in average sales prices decreased, which resultedreceived on our oil production for the year ended December 31, 2018 reflects the increase in net unrealized losses on derivatives ofthe index price for oil in 2018 as compared to 2017.

Natural gas sales. Our natural gas sales increased by approximately $232$26.8 million, or 55%, to $76.1 million for the year ended December 31, 2010. For information about LINN’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $75 million or 47% to approximately $2332018 from $49.2 million for the year ended December 31, 2011,2017. This increase was primarily due to the increase in production, partially offset by a decrease in average sales prices received for those produced volumes and the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our natural gas production increased 24,308 MMcf, or 138%, to 41,890 MMcf for the year ended December 31, 2018 from 17,582 MMcf for the year ended December 31, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Old Linn in August 2017 and drilling activity in the fourth quarter of 2017 and throughout 2018. The decrease in average sales prices received on our natural gas production for the year ended December 31, 2018 reflects the decrease in the Oklahoma index prices we received under our contract terms for natural gas in 2018 as compared to 2017. Additionally, our average sales price for the year ended December 31, 2018 was reduced by transportation costs for the produced natural gas volumes.

NGL sales. Our NGL sales increased by approximately $158$48.2 million, or 120%, to $88.5 million for the year ended December 31, 2010. Lease operating expenses per Mcfe also increased to $1.73 per Mcfe for the

Index to Financial Statements

year ended December 31, 2011,2018 from $1.64 per Mcfe for the year ended December 31, 2010. Lease operating expenses increased primarily due to costs associated with properties acquired during 2010 and 2011. Temporary oil handling costs in the Granite Wash formation and higher post-acquisition maintenance costs in the Permian Basin also contributed to the increase.

Transportation Expenses

Transportation expenses increased by approximately $9 million or 45% to approximately $28$40.3 million for the year ended December 31, 2011,2017. This increase was primarily due to the increase in production, partially offset by a decrease in the average sales prices received for those produced volumes and the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our NGL production increased 3,068 MBbls, or 201%, to 4,592 MBbls for the year ended December 31, 2018 from approximately $191,524 MBbls for the year ended December 31, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Old Linn in August 2017 and drilling activity in the fourth quarter of 2017 and throughout 2018. The decrease in our average sales price for the year ended December 31, 2018 was primarily a result of transportation costs for the produced NGL volumes being netted against revenue.

Gain (loss) on derivative contracts. For the year ended December 31, 2018, changes in oil prices had a positive impact on the fair value of our derivative contracts. We had a gain on derivative contracts of $78.1 million, including a loss on settlement of derivatives contracts of $33.3 million and a favorable change in the fair value of derivative contracts of $111.4 million. For the year ended December 31, 2017, changes in oil prices had a negative impact on the fair value of our derivative contracts. We had a loss on derivative contracts of $6.8 million, including an unfavorable change in the fair value of derivative contracts of $9.5 million partially offset by $2.7 million gain on settlement of natural gas and oil derivative contracts in 2017. Included in the $2.7 million gain on settlement of natural gas and oil contracts in 2017 was a $1.3 million gain on the settlement of derivative contracts prior to their contractual maturity.

Operating Expenses

The following table provides information on our operating expenses:

   Year Ended
December 31,
 
   2018   2017 
   (in thousands, except per Boe) 

Operating Expenses

    

Production expenses

  $47,600   $16,872 

Gathering, transportation and processing(1)

   —      18,602 

Production taxes

   17,579    3,685 

Exploration expenses

   43,303    32,629 

Depreciation, depletion, amortization and accretion

   123,922    37,376 

General and administrative(2)

   60,874    31,357 

Gain on sale of oil and natural gas properties

   —      (838
  

 

 

   

 

 

 

Total

  $293,278   $139,683 
  

 

 

   

 

 

 

Average Costs per Boe

    

Production expenses

  $2.99   $2.86 

Gathering, transportation and processing(1)

   —      3.15 

Production taxes

   1.10    0.62 

Exploration expenses

   2.72    5.52 

Depreciation, depletion, amortization and accretion

   7.78    6.33 

General and administrative(2)

   3.82    5.31 

Gain on sale of oil and natural gas properties

   —      (0.14
  

 

 

   

 

 

 

Total

  $18.41   $23.65 
  

 

 

   

 

 

 

(1)

Gathering, transportation and processing for the year ended December 31, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

(2)

General and administrative expenses for the year ended December 31, 2018 and 2017 include $11.0 million, or $0.69 per Boe, and $0.4 million or $0.06 per Boe, of equity-based compensation expense.

Production expenses. Production expenses were $47.6 million, or $2.99 per Boe, for the year ended December 31, 2018, which was an increase of $30.7 million, or 182%, from $16.9 million, or $2.86 per Boe, for the year ended December 31, 2017. The increase in production expenses during 2018 compared to 2017 was primarily due to increased production.

Gathering, transportation and processing. Gathering, transportation, and processing costs were $18.6 million, or $3.15 per Boe, for the year ended December 31, 2017. As a result of adopting ASC 606 in January 2018, these costs are reflected as a deduction from revenue for the year ended December 31, 2018.

Production taxes. Production taxes were $17.6 million for the year ended December 31, 2010, primarily due to higher production volumes.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs2018, an increase of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $34$13.9 million, or 35% to approximately $133377%, from $3.7 million for the year ended December 31, 2011,2017. Production taxes primarily increased due to increased revenues and increased production tax rates, which became effective in July 2018.

Exploration expenses.For the year ended December 31, 2018, exploration expenses of $43.3 million included amortization of unproved leasehold of $36.0 million and geological and geophysical expenses of $7.3 million. For the year ended December 31, 2017, exploration expenses of $32.6 million consisted of unproved

leasehold amortization of $19.6 million, impairment on unproved property of $4.5 million and geological and geophysical expenses of $7.3 million. Unproved leasehold amortization is calculated by considering our drilling plans and the lease terms of our existing unproved properties. The increase in exploration expenses is due, in part, to amortization of unproved leasehold associated with the oil and natural gas properties contributed by Old Linn.

Depreciation, depletion, amortization and accretion.Depreciation, depletion, amortization and accretion was $123.9 million, or $7.78 per Boe, for the year ended December 31, 2018, and $37.4 million, or $6.33 per Boe, for the year ended December 31, 2017, which is an increase of $86.5 million or 232%. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production and, to a lesser extent, an increase in the depletion rate for our oil and natural gas properties. The per Boe increase in the depletion rate is attributable to higher capital expenditures in 2018.

General and administrative. General and administrative expenses were $60.9 million, or $3.82 per Boe, for the year ended December 31, 2018, an increase of $29.5 million or 94% from $31.4 million, or $5.31 per Boe, for the year ended December 31, 2017. During the year ended December 31, 2018, general and administrative expenses included salaries and benefits of $21.7 million and equity-based compensation expense of $11.0 million. Additionally, we incurred consulting and professional fees as part of the implementation of systems and processes and transition efforts in 2018 as well as $4.6 million of costs associated with the Reorganization. These expenses were offset by bonuses paid by Citizen of approximately $99$9.0 million during the year ended December 31, 2017.

Other Expenses

Interest expense, net. Interest expense, net of capitalized interest, for the year ended December 31, 2018 was $8.4 million as compared to $1.5 million for the year ended December 31, 2010. The2017. This increase was primarily due to an increase in salaries and benefitsincreased borrowings outstanding during the year ended December 31, 2018 as compared to the year ended December 31, 2017.

Income tax expense. Income tax expense of approximately $18 million, driven primarily by increased employee headcount, an increase in unit-based compensation expense of approximately $8 million, an increase in professional services expense of approximately $3 million and an increase in acquisition integration expenses of approximately $3 million. General and administrative expenses per Mcfe decreased to $0.99 per Mcfe for the year ended December 31, 2011, from $1.02 per Mcfe for2018 was $356.9 million and includes $304.5 million related to the year endedrecognition of a deferred tax liability upon becoming a taxable entity in conjunction with the Reorganization. The remainder of the income tax expense related to the applicable effective tax rate on taxable income following the Reorganization.

Year Ended December 31, 2010, due2017 Compared to higher production volumes.Year Ended December 31, 2016

   For the Year Ended
December 31,
 
   2017   2016 
Production Data:    

Oil (MBbls)

   1,454    739 

Natural gas (MMcf)

   17,582    6,382 

Natural gas liquids (MBbls)

   1,524    546 

Total volumes (MBoe)

   5,908    2,349 

Average daily total volumes (MBoe/d)

   16.2    6.3 

Average Prices – as reported:

    

Oil (per Bbl)

  $52.87   $41.36 

Natural gas (per Mcf)

  $2.80   $2.52 

Natural gas liquids (per Bbl)

  $26.44   $15.21 

Total (per Boe)

  $28.16   $23.40 

Average Prices – including impact of derivative contract settlements(1):

    

Oil (per Bbl)

  $53.57   $41.36 

Natural gas (per Mcf)

  $2.89   $2.52 

Natural gas liquids (per Bbl)

  $26.44   $15.21 

Total (per Boe)

  $28.60   $23.40 

(1)

Excludes settlement of derivative contracts prior to their contractual maturity.

Exploration CostsRevenues

Exploration costs decreasedOur operating revenues are primarily from the sale of oil, natural gas and NGLs. The following table provides information on our operating revenues:

   For the Year Ended
December 31,
 
   2017   2016 
   (in thousands) 

Revenues

    

Oil sales

  $76,876   $30,565 

Natural gas sales

   49,211    16,093 

Natural gas liquid sales

   40,298    8,307 

Loss on derivative contracts

   (6,797   —   
  

 

 

   

 

 

 

Total revenues

  $159,588   $54,965 
  

 

 

   

 

 

 

Oil sales. Our oil sales increased by approximately $3$46.3 million, or 54%152%, to approximately $2$76.9 million for the year ended December 31, 2011,2017 from approximately $5$30.6 million for the year ended December 31, 2010. The decrease2016. This increase was primarily due to lower leasehold impairment expensesincreased production and an increase in the average sales price received for our produced volumes. Our oil production increased by 715 MBbls, or 97%, for the year ended December 31, 2017 compared with the year ended December 31, 2016. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Old Linn in August 2017 and drilling activity in 2017. The increase in average sales prices received on unproved properties.our oil production for the year ended December 31, 2017 reflects the increase in the index price for the year ended December 31, 2017 as compared to the year ended December 31, 2016.

Depreciation, Depletion and AmortizationNatural Gas sales.

Depreciation, depletion and amortization Our natural gas sales increased by approximately $95$33.1 million, or 40%206%, to approximately $334$49.2 million for the year ended December 31, 2011,2017 from approximately $239$16.1 million for the year ended December 31, 2010. Higher total2016. This increase was due to increased production volumes were the primary reasonand an increase in average sales prices received for theour produced volumes. Our natural

gas production increased expense. Depreciation, depletion and amortization per Mcfe increased to $2.48 per Mcfeby 11,200 MMcf, or 175%, for the year ended December 31, 2011, from $2.46 per Mcfe2017 compared with the year ended December 31, 2016. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Old Linn in August 2017 and drilling activity in 2017. The increase in average sales prices received on our natural gas production for the year ended December 31, 2010.

Impairment of Long-Lived Assets

LINN recorded no impairment charge2017 reflects the increase in the index price for the year ended December 31, 2011. During2017 as compared to the year ended December 31, 2010, LINN recorded a noncash impairment charge of approximately $39 million primarily associated with the impairment of proved oil and natural gas properties related to an unfavorable marketing contract. See “Critical Accounting Policies and Estimates” below for additional information.2016.

Taxes, Other Than Income TaxesNGL sales.

Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, Our NGL sales increased by approximately $34$32.0 million, or 74%385%, to approximately $79$40.3 million for the year ended December 31, 2011,2017 from approximately $45$8.3 million for the year ended December 31, 2010. Severance taxes, which are a function of revenues generated from2016. This increase was primarily due to increased production as well as an increase in average sales prices received for our produced volumes. Our NGL production increased by approximately $31 million compared to978 MBbls, or 179%, for the year ended December 31, 2010, primarily due to higher commodity prices and higher production volumes. Ad valorem

Index to Financial Statements

taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $3 million2017 compared towith the year ended December 31, 2010, primarily2016. The increase in production volumes was due to property acquisitionsproduction associated with oil and natural gas properties contributed by Old Linn in 2011.August 2017 and drilling activity in 2017. The increase in average sales prices received on our NGL production for the year ended December 31, 2017 reflects the increase in the index prices for NGLs in 2017.

Other IncomeLoss on derivative contracts. For the year ended December 31, 2017, changes in oil prices had a negative impact on the fair value of our derivative contracts. We had a loss on derivative contracts of $6.8 million, including unfavorable change in the fair value of derivative contracts of $9.5 million partially offset by $2.7 million gain on settlement of natural gas and (Expenses)

   Year Ended December 31,    
   2010  2011  Variance 
   (in thousands) 

Loss on extinguishment of debt

  $—     $(94,612 $(94,612

Interest expense, net of amounts capitalized

   (193,510  (259,725  (66,215

Realized losses on interest rate swaps

   (8,021  —      8,021  

Realized losses on canceled interest rate swaps

   (123,865  —      123,865  

Unrealized gains on interest rate swaps

   63,978    —      (63,978

Other, net

   (7,167  (7,792  (625
  

 

 

  

 

 

  

 

 

 
  $(268,585 $(362,129 $(93,544
  

 

 

  

 

 

  

 

 

 

Other incomeoil derivative contracts in 2017. Included in the $2.7 million gain on settlement of natural gas and (expenses) increased by approximately $94oil contracts in 2017 was a $1.3 million gain on the settlement of derivative contracts prior to their contractual maturity. There were no derivative contracts in place during the year ended December 31, 2011, compared to2016.

Operating Expenses

Our operating expenses reflect costs incurred in the year ended December 31, 2010. Interest expense increased primarily due to higher outstanding debt during the perioddevelopment, production and higher amortizationsale of financing fees associated with the 2019 Senior Notesoil, natural gas and the 2010 Issued Senior Notes, as defined in Note 6 to LINN’s historical audited financial statementsNGLs. The following table provides information on our operating expenses:

   For the Year Ended
December 31,
 
   2017   2016 
   (in thousands, except per Boe) 

Operating Expenses

    

Production expenses

  $16,872   $5,090 

Gathering, transportation and processing

   18,602    5,920 

Production taxes

   3,685    1,087 

Exploration expenses

   32,629    5,258 

Depreciation, depletion, amortization and accretion

   37,376    24,996 

General and administrative(1)

   31,357    5,581 

Gain on sale of oil and natural gas properties

   (838   —   
  

 

 

   

 

 

 

Total

  $139,683   $47,932 
  

 

 

   

 

 

 

Average Costs per Boe:

    

Production expenses

  $2.86   $2.17 

Gathering, transportation and processing

   3.15    2.52 

Production taxes

   0.62    0.46 

Exploration expenses

   5.52    2.24 

Depreciation, depletion, amortization and accretion

   6.33    10.64 

General and administrative(1)

   5.31    2.38 

Gain on sale of oil and natural gas properties

   (0.14   —   
  

 

 

   

 

 

 

Total

  $23.65   $20.41 
  

 

 

   

 

 

 

(1)

General and administrative expenses for the year ended December 31, 2017 include $0.4 million, or $0.06 per Boe, of equity-based compensation expense.

Production expenses. Production expenses were $16.9 million, or $2.86 per Boe, for the year ended December 31, 2011, included elsewhere in this prospectus. In addition, in May 2011 LINN entered into a Fifth Amended and Restated Credit Facility,2017, which also resulted in higher amortizationwas an increase of financing fees. For the year ended December 31, 2011, LINN also recorded a loss on extinguishment of debt of approximately $95$11.8 million, as a result of the redemptions, cash tender offers and additional repurchases of a portion of the Original Senior Notes, as defined in Note 6 to LINN’s historical audited financial statementsor 231%, from $5.1 million, or $2.17 per Boe, for the year ended December 31, 2011, included elsewhere2016. The increase in this prospectus. See “Debt”production expenses during 2017 compared to 2016 was primarily due to increased production.

Gathering, transportation and processing. Gathering, transportation, and processing costs were $18.6 million, or $3.15 per Boe, for the year ended December 31, 2017, which was an increase of $12.7 million, or 215%, from $5.9 million, or $2.52 per Boe, for the year ended December 31, 2016. The increase in “Liquiditygathering, transportation and Capital Resources” below for additional details.processing costs during 2017 as compared to 2016 was primarily related to increased production.

Income Tax Benefit (Expense)Production taxes.

LINN is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of LINN passed through to unitholders. Limited liability companies are subject to Texas margin tax. Limited liability companies Production taxes were also subject to state income taxes in Michigan during the three months ended March 31, 2011. In addition, certain of LINN’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. LINN recognized income tax expense of approximately $5$3.7 million for the year ended December 31, 2011, compared to approximately $4 million for the same period in 2010. Income tax expense increased primarily due to higher income in 2011 from LINN’s taxable subsidiaries.

Net Income (Loss)

Net income increased by approximately $5522017, which was an increase of $2.6 million, or 484% to approximately $438239%, from $1.1 million for the year ended December 31, 2011,2016. Production taxes primarily increased due to increased revenues.

Exploration expenses. For the year ended December 31, 2017, exploration expenses of $32.6 million consisted of unproved leasehold amortization of $19.6 million, impairment on unproved property of $4.5 million and geological and geophysical expenses of $7.3 million. For the year ended December 31, 2016, exploration expenses of $5.3 million consisted of impairment expense recognized related to our unproved properties. The increase in exploration expenses is due, in part, to amortization of unproved leasehold associated with the oil and natural gas properties contributed by Old Linn and costs associated with seismic information acquired in 2017.

Depreciation, depletion, amortization and accretion.Depreciation, depletion, amortization and accretion was $37.4 million, or $6.33 per Boe, for the year ended December 31, 2017, which was an increase of $12.4 million, or 50%, from a net loss$25.0 million, or $10.64 per Boe, for the year ended December 31, 2016. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production.

General and administrative.General and administrative expenses were $31.4 million, or $5.31 per Boe, for the year ended December 31, 2017, which was an increase of $25.8 million, or 462%, from $5.6 million, or $2.38 per Boe, for the year ended December 31, 2016. During the year ended December 31, 2017, general and administrative expenses included fees paid to Citizen and Old Linn under our MSAs of $10.0 million, bonuses paid by Citizen of approximately $114$9.0 million, equity-based compensation expense of $0.4 million and professional and consulting expenses related to Roan’s transition and system implementation.

Other Expenses

Interest expense. Interest expense for the year ended December 31, 2017 was $1.5 million as compared to $0.1 million for the year ended December 31, 2010. The2016. This increase was primarily due higher production revenuesto increased borrowings outstanding during 2017 as compared to 2016.

Liquidity and higher gains on oilCapital Resources

Our primary sources of liquidity have been borrowings under our credit facility and natural gas derivatives, partially offset by higher expenses, including interest. The year ended December 31, 2010 also included an impairmentcash flows from operations. Our primary uses of long-lived assets and realized and unrealized losses on interest rate swaps; there were no comparable amounts reportedcapital have been for the year ended December 31, 2011. See discussions above for explanations of variances.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $266 million or 36% to approximately $998 million for the year ended December 31, 2011, from approximately $732 million for the year

Index to Financial Statements

ended December 31, 2010. The increase was primarily due to higher production revenues resulting from higher production volumesexploration, development and higher commodity prices, partially offset by higher expenses. See “Non-GAAP Financial Measures” for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP. See discussions above for explanations of variances.

Adjusted Net Income

Adjusted net income increased by approximately $94 million or 43% to approximately $313 million for the year ended December 31, 2011, from approximately $219 million for the year ended December 31, 2010. The increase was primarily due to higher production revenues partially offset by lower realized gains on oil and natural gas derivatives and higher expenses, including interest. The year ended December 31, 2010 also included realized losses on interest rate swaps; there was no comparable amount reported for the year ended December 31, 2011. See discussions above for explanations of variances.

Results of Operations

Year Ended December 31, 2010, Compared to Year Ended December 31, 2009

   Year Ended December 31,    
   2009  2010  Variance 
   (in thousands) 

Revenues and other:

    

Natural gas sales

  $160,470   $211,596   $51,126  

Oil sales

   181,619    359,996    178,377  

NGL sales

   66,130    118,462    52,332  
  

 

 

  

 

 

  

 

 

 

Total oil, natural gas and NGL sales

   408,219    690,054    281,835  

Gains (losses) on oil and natural gas derivatives(1)

   (141,374  75,211    216,585  

Marketing and other revenues

   6,304    7,015    711  
  

 

 

  

 

 

  

 

 

 
   273,149    772,280    499,131  
  

 

 

  

 

 

  

 

 

 

Expenses:

    

Lease operating expenses

   132,647    158,382    25,735  

Transportation expenses

   18,202    19,594    1,392  

Marketing expenses

   2,154    2,716    562  

General and administrative expenses(2)

   86,134    99,078    12,944  

Exploration costs

   7,169    5,168    (2,001

Depreciation, depletion and amortization

   201,782    238,532    36,750  

Impairment of long-lived assets

   —      38,600    38,600  

Taxes, other than income taxes

   27,605    45,182    17,577  

(Gains) losses on sale of assets and other, net

   (24,197  6,490    30,687  
  

 

 

  

 

 

  

 

 

 
   451,496    613,742    162,246  
  

 

 

  

 

 

  

 

 

 

Other income and (expenses)

   (121,715  (268,585  (146,870
  

 

 

  

 

 

  

 

 

 

Loss from continuing operations before income taxes

   (300,062  (110,047  190,015  

Income tax benefit (expense)

   4,221    (4,241  (8,462

Discontinued Operations

   (2,351  —      2,351  
  

 

 

  

 

 

  

 

 

 

Net loss

  $(298,192 $(114,288 $183,904  
  

 

 

  

 

 

  

 

 

 

Adjusted EBITDA(3)

  $566,235   $732,131   $165,896  
  

 

 

  

 

 

  

 

 

 

Adjusted net income(3)

  $206,922   $219,489   $12,567  
  

 

 

  

 

 

  

 

 

 

(1)During the year ended December 31, 2009, LINN canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized net gains of approximately $49 million, primarily associated with LINN’s commodity derivative repositioning in July 2009.

Index to Financial Statements
(2)General and administrative expenses for the years ended December 31, 2009, and December 31, 2010, include approximately $15 million and $13 million, respectively, of noncash unit-based compensation expenses.
(3)This is a non-GAAP measure used by management to analyze LINN’s performance. See “—Non-GAAP Financial Measures” for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

   Year Ended December 31,     
       2009           2010       Variance 

Average daily production:

      

Natural gas (MMcf/d)

   125     137     10

Oil (MBbls/d)

   9.0     13.1     46

NGL (MBbls/d)

   6.5     8.3     28

Total (MMcfe/d)

   218     265     22

Weighted average prices (hedged):(1)

      

Natural gas (Mcf)

  $8.27    $8.52     3

Oil (Bbl)

  $110.94    $94.71     (15)% 

NGL (Bbl)

  $28.04    $39.14     40

Weighted average prices (unhedged):(2)

      

Natural gas (Mcf)

  $3.51    $4.24     21

Oil (Bbl)

  $55.25    $75.16     36

NGL (Bbl)

  $28.04    $39.14     40

Average NYMEX prices:

      

Natural gas (MMBtu)

  $3.99    $4.40     10

Oil (Bbl)

  $61.94    $79.53     28

Costs per Mcfe of production:

      

Lease operating expenses

  $1.67    $1.64     (2)% 

Transportation expenses

  $0.23    $0.20     (13)% 

General and administrative expenses(3)

  $1.08    $1.02     (6)% 

Depreciation, depletion and amortization

  $2.53    $2.46     (3)% 

Taxes, other than income taxes

  $0.35    $0.47     34

(1)Includes the effect of realized gains on derivatives of approximately $401 million (excluding $49 million realized net gains on canceled contracts) and $308 million for the years ended December 31, 2009, and December 31, 2010, respectively.
(2)Does not include the effect of realized gains (losses) on derivatives.
(3)General and administrative expenses for the years ended December 31, 2009, and December 31, 2010, include approximately $15 million and $13 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the years ended December 31, 2009, and December 31, 2010, were $0.90 per Mcfe and $0.88 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze LINN’s performance.

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $282 million or 69% to approximately $690 million for the year ended December 31, 2010, from approximately $408 million for the year ended December 31, 2009, due to higher commodity prices and higher production volumes. Higher oil, natural gas and NGL prices resulted in an increase in revenues of approximately $95 million, $36 million and $34 million, respectively.

Index to Financial Statements

Average daily production volumes increased to 265 MMcfe/d during the year ended December 31, 2010, from 218 MMcfe/d during the year ended December 31, 2009. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $83 million, $15 million and $19 million, respectively.

The following sets forth average daily production by region, as established for LINN during 2010 and 2009:

   Year Ended December 31,        
   2009   2010   Variance 

Average daily production (MMcfe/d):

       

Mid-Continent Deep

   135     133     (2  (1)% 

Mid-Continent Shallow

   67     66     (1  (1)% 

Permian Basin

   2     31     29    1,450

Michigan

   —       21     21    —    

California

   14     14     —      —    
  

 

 

   

 

 

   

 

 

  
   218     265     47    22
  

 

 

   

 

 

   

 

 

  

The 1% decrease in average daily production volumes in the Mid-Continent Deep region primarily reflects natural declines, in addition to minimal capital development during the second half of 2009 due to low commodity prices, partially offset by the impact of LINN’s 2010 capital drilling program in the Deep Granite Wash formation. Average daily production volumes in the Mid-Continent Shallow region reflect the impact of drilling and optimization programs which offset the effects of natural declines. Average daily production volumes in the Permian Basin region reflect the impact of the acquisitions in 2010 and the third quarter of 2009 and subsequent development capital spending. Average daily production volumes in the Michigan region reflect the impact of LINN’s acquisitions in this area in 2010. The California region consists of a low-decline asset base and continues to produce at levels consistent with prior year.

Gains (Losses) on Oil and Natural Gas Derivatives

LINN determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. During the year ended December 31, 2010, LINN had commodity derivative contracts for approximately 114% of its natural gas production and 97% of its oil production, which resulted in realized gains of approximately $308 million. During the year ended December 31, 2009, LINN recorded realized gains of approximately $450 million (including realized net gains on canceled contracts of approximately $49 million). Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, unrealized losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, unrealized gains are recognized. During 2010, expected future oil prices increased and expected future natural gas prices decreased, which resulted in net unrealized losses on derivatives of approximately $232 million for the year ended December 31, 2010. During 2009, expected future oil prices increased and expected future natural gas prices decreased, which resulted in net unrealized losses on derivatives of approximately $591 million for the year ended December 31, 2009. For information about LINN’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $25 million or 19% to approximately $158 million for the year ended December 31, 2010, from approximately $133 million for

Index to Financial Statements

the year ended December 31, 2009. Lease operating expenses increased primarily due to costs associated with properties acquired in the Permian Basin and Michigan regions in 2010 and the second half of 2009. Lease operating expenses per Mcfe decreased to $1.64 per Mcfe for the year ended December 31, 2010, from $1.67 per Mcfe for the year ended December 31, 2009.

Transportation Expenses

Transportation expenses increased by approximately $1 million or 8% to approximately $19 million for the year ended December 31, 2010, from approximately $18 million for the year ended December 31, 2009, primarily due to higher total production volume levels from LINN’s acquisitions in the Permian Basin and Michigan regions in 2010 and the second half of 2009, partially offset by lower rates associated with owned facilities.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $13 million or 15% to approximately $99 million for the year ended December 31, 2010, from approximately $86 million for the year ended December 31, 2009. The increase was primarily due to an increase in salaries and benefits expense of approximately $10 million, driven primarily by increased employee headcount, and acquisition integration expenses of approximately $4 million. General and administrative expenses per Mcfe decreased to $1.02 per Mcfe for the year ended December 31, 2010, from $1.08 per Mcfe for the year ended December 31, 2009.

Exploration Costs

Exploration costs decreased by approximately $2 million or 28% to approximately $5 million for the year ended December 31, 2010, from approximately $7 million for the year ended December 31, 2009. The decrease was primarily due to fewer lease-term expirations related to unproved leasehold costs.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $37 million or 18% to approximately $239 million for the year ended December 31, 2010, from approximately $202 million for the year ended December 31, 2009. Higher total production volume levels, primarily due to LINN’s acquisitions in the Permian Basin and Michigan regions in 2010 and in the Permian Basin region in the second half of 2009, were the main reason for the increase. Depreciation, depletion and amortization per Mcfe decreased to $2.46 per Mcfe for the year ended December 31, 2010, from $2.53 per Mcfe for the year ended December 31, 2009.

Impairment of Long-Lived Assets

During the year ended December 31, 2010, LINN recorded a noncash impairment charge of approximately $39 million primarily associated with the impairment of proved oil and natural gas properties related to an unfavorable marketing contract. LINN recorded no impairment charge for the year ended December 31, 2009. See “Critical Accounting Policies and Estimates” below for additional information.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $17 million or 64% to approximately $45 million for the year ended December 31, 2010, from approximately $28 million for the year ended December 31, 2009. Severance taxes, which are a function of revenues generated from production, increased by approximately $14 million compared to the year ended

Index to Financial Statements

December 31, 2009, primarily due to higher commodity prices and higher total production volume levels. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $2 million compared to the year ended December 31, 2009, primarily due to property acquisitions in the Permian Basin region.

Other Income and (Expenses)

   Year Ended December 31,    
   2009  2010  Variance 
   (in thousands) 

Interest expense, net of amounts capitalized

  $(92,701 $(193,510 $(100,809

Realized losses on interest rate swaps

   (42,881  (8,021  34,860  

Realized losses on canceled interest rate swaps

   (60  (123,865  (123,805

Unrealized gains on interest rate swaps

   16,588    63,978    47,390  

Other, net

   (2,661  (7,167  (4,506
  

 

 

  

 

 

  

 

 

 
  $(121,715 $(268,585 $(146,870
  

 

 

  

 

 

  

 

 

 

Other income and (expenses) increased by approximately $147 million during the year ended December 31, 2010, compared to the year ended December 30, 2009. During the year ended December 31, 2010, LINN canceled (before the contract settlement date) all of its interest rate swap agreements, resulting in higher realized losses of approximately $124 million. These losses were partially offset by an increase in unrealized gains on interest rate swaps and a decrease in realized losses on interest rate swaps during the year ended December 31, 2010, compared to the year ended December 31, 2009. Additionally, in the second and third quarters of 2010, LINN entered into an amendment to its Credit Facility and issued the 2010 Issued Senior Notes, as defined in Note 6 to LINN’s historical audited financial statements for the year ended December 31, 2011, included elsewhere in this prospectus, which resulted in increased interest expense due to higher interest rates and higher amortization of financing fees. See “Debt” in “Liquidity and Capital Resources” below for additional details.

Income Tax Benefit (Expense)

LINN is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of LINN passed through to unitholders. Limited liability companies are subject to state income taxes in Texas and Michigan. In addition, certain of LINN’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. LINN recognized an income tax expense of approximately $4 million for the year ended December 31, 2010, compared to an income tax benefit of approximately $4 million for the same period in 2009. Income tax expense increased primarily due to an increase in income in 2010 from LINN’s taxable subsidiaries. In 2009, LINN released a valuation allowance on a significant portion of the deferred tax assets at LINN’s taxable subsidiaries.

Net Loss

Net loss decreased by approximately $184 million or 62% to approximately $114 million for the year ended December 31, 2010, from approximately $298 million for the year ended December 31, 2009. The decrease was primarily due to higher production revenues and higher gains on oil and natural gas derivatives, partially offset by higher expenses, including interest. See discussions above for explanations of variances.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $166 million or 29% to approximately $732 million for the year ended December 31, 2010, from approximately $566 million for the year ended December 31, 2009. The increase was primarily due to higher production revenues resulting from higher

Index to Financial Statements

commodity prices and higher total production volume levels, partially offset by lower realized gains on commodity derivatives. See “Non-GAAP Financial Measures” for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP. See discussions above for explanations of variances.

Adjusted Net Income

Adjusted net income increased by approximately $12 million or 6% to approximately $219 million for the year ended December 31, 2010, from approximately $207 million for the year ended December 31, 2009. The increase was primarily due to higher production revenues, partially offset by higher expenses, including interest and income taxes, and higher realized losses on interest rate swaps. See discussions above for explanations of variances.

Reserve Replacement Metrics

LINN calculates two primary reserve metrics: (i) reserve replacement cost and (ii) reserve replacement ratio, to measure its ability to establish a long-term trend of adding reserves at a reasonable cost. The reserve replacement cost calculation provides an assessment of the cost of adding reserves that is ultimately included in depreciation, depletion and amortization expense. The reserve replacement ratio is an indicator of LINN’s ability to replenish annual production volumes and grow reserves. The metrics are calculated as follow:

Reserve replacement cost per Mcfe=

Oil and natural gas capital costs expended(1)

Sum of reserve additions(2)

Reserve replacement ratio

=

Sum of reserve additions(2)

Annual production

(1)Oil and natural gas capital costs expended include the costs of property acquisition, exploration and development activities conducted to add reserves and exclude asset retirement costs. LINN expects to incur development costs in the future for proved undeveloped reserves; such future costs are excluded from costs expended and are not considered in the reserve replacement metrics presented herein.
(2)Reserve additions include proved reserves (developed and undeveloped) and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities.

The reserve replacement metrics are presented separately, both: (i) including and excluding the impact of price revisions on reserves, to demonstrate the effectiveness of LINN’s drilling program exclusive of economic factors (such as price) outside of its control and (ii) including and excluding acquisitions, to demonstrate LINN’s ability to add reserves through its drilling program and through acquisitions. Reserve replacement cost and reserve replacement ratio are non-GAAP financial measures. The methods used by LINN to calculate these measures may differ from methods used by other companies to compute similar measures. As a result, LINN’s measures may not be comparable to similar measures provided by other companies. LINN believes that providing such measures is useful in evaluating the cost to add proved reserves; however, these measures should not be considered in isolation or as a substitute for GAAP measures. The reserve replacement cost per Mcfe and reserve replacement ratio are statistical indicators that have limitations, including their predictive and comparative value. The reserve replacement ratio is limited because it may vary widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions. In addition, since the reserve replacement ratio does not consider the development cost or timing of future production of new reserves, it should not be used as a measure of value creation.

Index to Financial Statements

The following presents reserve replacement cost and reserve replacement ratio including and excluding the effect of price revisions on reserves:

   Including Price Revisions  Excluding Price Revisions 
   Year Ended December 31,  Year Ended December 31, 
   2009  2010  2011  2009  2010  2011 

Costs per Mcfe of production:

       

Reserve replacement cost, including acquisitions

  $1.96   $1.63   $2.37   $1.71   $1.94   $2.46  

Reserve replacement cost, excluding acquisitions (finding and development cost)

  $2.03   $0.79   $1.94   $1.59   $1.57   $2.15  

Percentage of production:

       

Reserve replacement ratio, including acquisitions

   165  1,014  674  189  854  651

Reserve replacement ratio, excluding acquisitions

   88  321  244  112  161  221

Amounts used in these calculations and are derived directly from the table presented in “Supplemental Oil and Natural Gas Data (Unaudited)” in LINN’s historical audited financial statements for the year ended December 31, 2011, included elsewhere in this prospectus. The following provides a reconciliation of oil and natural gas capital costs used in these calculations to its most directly comparable financial measure calculated and presented in accordance with GAAP:properties.

   Year Ended December 31, 
   2009  2010  2011 
   (in thousands) 

Costs incurred in oil and natural gas property acquisition, exploration and development

  $258,105   $1,602,086   $2,158,639  

Less:

    

Asset retirement costs

   (371  (748  (2,427

Property acquisition costs

   (115,929  (1,356,430  (1,516,737
  

 

 

  

 

 

  

 

 

 

Oil and natural gas capital costs expended, excluding acquisitions

  $141,805   $244,908   $639,475  
  

 

 

  

 

 

  

 

 

 

Liquidity and Capital Resources

LINN utilizes funds from equity and debt offerings, bank borrowings and cash flow from operations for capital resources and liquidity. To date, the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the year ended December 31, 2011, LINN’s total capital expenditures, excluding acquisitions, were approximately $697 million. For the three months ended March 31, 2012, LINN’s capital expenditures, excluding acquisitions, were approximately $259 million. For 2012, LINN estimates its total capital expenditures, excluding acquisitions, will be approximately $1.0 billion, including $940 million related to its oil and natural gas capital program and $40 million related to its plant and pipeline capital. This estimate reflects amounts for the development of properties associated with acquisitions, is under continuous review and subject to ongoing adjustments. LINN expects to fund these capital expenditures primarily with cash flow from operations and bank borrowings.

As LINN pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. LINN’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves. LINN actively reviews acquisition opportunities on an ongoing basis. If LINN were to make significant additional acquisitions for cash, it would need to borrow additional amounts under its Credit Facility, if available, or obtain additional debt or equity financing. LINN’s Credit Facility and indentures governing its Senior Notes impose certain restrictions on LINN’s ability to obtain additional debt financing. Based upon current expectations, LINN believes liquidity and capital resources will be sufficient to conduct its business and operations.

Index to Financial Statements

Statements of Cash Flows

The following is a comparativetable summarizes our cash flow summary:flows for the periods indicated:

 

   Year Ended December 31,  Three Months Ended
March  31,
 
   2009  2010  2011  2011  2012 
   (in thousands) 

Net cash:

      

Provided by operating activities(1)

  $426,804   $270,918   $518,706   $107,966   $35,513  

Used in investing activities

   (282,273  (1,581,408  (2,130,360  (358,068  (1,460,555

Provided by (used in) financing activities

   (150,968  1,524,260    1,376,767    209,425    1,448,112  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net increase (decrease) in cash and cash equivalents

  $(6,437 $213,770   $(234,887 $(40,677 $23,070  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
   Three Months Ended
March 31,
  Year Ended December 31, 
   2019  2018  2018  2017  2016 
   (in thousands) 

Net cash provided by (used in) operating activities

  $63,615  $(8,774 $268,296  $60,275  $36,140 

Net cash used in investing activities

   (158,200  (11,254  (689,092  (212,521  (241,109

Net cash provided by financing activities

   89,891   121,300   426,208   146,864   189,008 
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net (decrease) increase in cash and cash equivalents

  $(4,694 $1,272  $5,412  $(5,382 $(15,961
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

(1)The years ended December 31, 2009, December 31, 2010, and December 31, 2011, and the three months ended March 31, 2012, include premiums paid for derivatives of approximately $94 million, $120 million, $134 million and $178 million, respectively.

Operating ActivitiesAnalysis of Cash Flow Changes Between Three Months Ended March 31, 2019 and 2018

Cash flows provided by operating activities. Cash flows provided by operating activities for the three months ended March 31, 2012, was approximately $362019 were $63.6 million compared to approximately $108cash flows used in operating activities of $8.8 million for the three months ended March 31, 2011.2018. The decrease was primarily due to approximately $178 million in premiums paid for commodity derivatives during the three months ended March 31, 2012, compared to no premiums paid during the same period in 2011. Higher premiums and higher expenses were partially offset by increased revenues primarily due to higher production volumes and higher oil prices.

Cashcash flows provided by operating activities for the year ended December 31, 2011, was approximately $519 million, compared to approximately $271 million for the year ended December 31, 2010. The increase wasin 2019 is primarily due to higher production volumesdriven by changes in working capital accounts and higher commodity pricesincreased revenues partially offset by higher expenses.

Cash provided by operating activities was approximately $271 million for the year ended December 31, 2010, compared to approximately $427 million for the year ended December 31, 2009. The decrease was primarilycash expenses due to approximately $124 millionhigher activity levels in realized losses on canceled interest rate derivatives during the year ended December 31, 2010, compared to approximately $49 million in realized net gains on canceled commodity derivatives during the year ended December 31, 2009.2019.

Premiums paid during 2011, 2010 and 2009 and during the three months ended March 31, 2012 were for commodity derivative contracts that hedge future production. These derivative contracts provide LINN long-term cash flow predictability to manage its business, service debt and pay distributions and are primarily funded through LINN’s Credit Facility. The amount of derivative contracts LINN enters into in the future will be directly related to expected future production.

Index to Financial Statements

Investing Activities

The following provides a comparative summary of cash flow from investing activities:

   Year Ended December 31,  Three Months Ended
March  31,
 
   2009  2010  2011  2011  2012 
   (in thousands) 

Cash flow from investing activities:

      

Acquisition of oil and natural gas properties, net of cash acquired

  $(130,735 $(1,351,033 $(1,500,193 $(257,349 $(1,230,304

Capital expenditures

   (178,242  (223,013  (629,864  (99,461  (230,466

Proceeds from sale of properties and equipment and other

   26,704    (7,362  (303  (1,258  215  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
  $(282,273 $(1,581,408 $(2,130,360 $(358,068 $(1,460,555
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

The primary use of cashCash flows used in investing activities is for capital spending, including acquisitions and the development of LINN’s oil and natural gas properties.activities. Cash flows used in investing activities for the three months ended March 31, 2012, primarily relates2019 were $158.2 million compared to $111.3 million for the Hugoton Acquisition. Cashthree months ended March 31, 2018. The increase in cash flows used in investing activities for the year ended December 31, 2011, primarily relates to acquisitions of properties in the Williston Basin, Permian Basin and Mid-Continent Deep regions. The year ended December 31, 2011, also includes the deposit of approximately $9 million returned to LINN by the other partyis due to the purchaseincrease in capital expenditures on oil and sale agreement (“PSA”) terminated by LINN in 2010.

Cash used in investing activities for the year ended December 31, 2010, primarily relates to acquisitions and the development ofnatural gas properties in the Permian Basin, Mid-Continent Deep and Michigan regions. Proceedsresulting from the sale of properties were lower for the year ended December 31, 2010,increase in drilling and completion activities in 2019 compared to the year ended December 31, 2009, primarily due to the proceeds receivedsame period in 2009 related to the sale of acreage in central Oklahoma. The year ended December 31, 2010, also includes the deposit made2018.

Cash flows provided by LINN of approximately $9 million held by the other party to the PSA terminated by LINN.financing activities. Cash used in investing activities for the year ended December 31, 2009, includes approximately $114 million for the acquisition of properties in the Permian Basin region.

Financing Activities

Cashflows provided by financing activities for the three months ended March 31, 2012, was approximately $1.4 billion,2019 were $89.9 million compared to approximately $209$121.3 million for the three months ended March 31, 2011. The increase in2018. Cash flows provided by financing cash flow needs was primarilyactivities for both periods are attributable to increased acquisitions and development activity duringborrowings from our credit facility. Borrowings from our credit facility decreased in the three months ended March 31, 2012.

2019 compared to the three months ended March 31, 2018 due to the increase in cash provided by operating activities being available for funding of capital expenditures for the period.

IndexAnalysis of Cash Flow Changes Between Year Ended December 31, 2018 and 2017

Cash flows provided by operating activities. Cash flows provided by operating activities for the year ended December 31, 2018 were $268.3 million compared to Financial Statements

$60.3 million for the year ended December 31, 2017. The increase in cash flows provided by operating activities is primarily related to increased revenues partially offset by higher cash expenses due to increased activity in 2018.

Cash flows used in investing activities. Cash flows used in investing activities for the year ended December 31, 2018 were $689.1 million compared to $212.5 million for the year ended December 31, 2017. The increase in cash flows used in investing activities is due to the increase in capital expenditures on oil and natural gas properties resulting from the increase in drilling and completion activities in 2018 compared to 2017.

Cash flows provided by financing activities. Cash flows provided by financing activities for the year ended December 31, 2011, was approximately $1.4 billion2018 were $426.2 million compared to approximately $1.5 billion for the year ended December 31, 2010. The decrease in financing cash flow needs was primarily attributable to the increase in cash provided by operating activities and the utilization of cash on hand. In comparison, cash used in financing activities was approximately $151$146.9 million for the year ended December 31, 2009.2017. The following provides a comparative summary of proceeds from borrowings and repayments of debt:

   Year Ended December 31,  Three Months Ended
March 31,
 
   2009  2010  2011  2011  2012 
   (in thousands) 

Proceeds from borrowings:

      

Credit facility

  $401,500   $1,050,000   $1,790,000   $160,000   $835,000  

Senior notes

   237,703    2,250,816    744,240    —      1,799,802  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
  $639,203   $3,300,816   $2,534,240   $160,000   $2,634,802  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Repayments of debt:

      

Credit facility

  $(704,893 $(2,150,000 $(850,000 $—     $(1,700,000

Senior notes

   —      —      (451,029  (408,397  —    
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
  $(704,893 $(2,150,000 $(1,301,029 $(408,397 $(1,700,000
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Debt

LINN’s Credit Facility provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. In October 2011, as part of the semi-annual redetermination, a borrowing base of $3.0 billion was approved by the lenders with a maximum commitment amount of $1.5 billion. In February 2012, lenders approved an increase in the maximum commitment amount to $2.0 billion. As a result of LINN’s March 2012 debt offering, the borrowing base was reduced from $3.0 billion to $2.6 billion, but LINN’s availability under the facility remains at the maximum commitment amount of $2.0 billion. The maturity date is April 2016. At March 31, 2012, available borrowing capacity was approximately $1.9 billion, which includes a $4 million reduction in availability for outstanding letters of credit.

On February 28, 2011, LINN commenced cash tender offers and related consent solicitations to purchase any and all of its outstanding 2017 Senior Notes and 2018 Senior Notes.

In March 2011, in accordance with the provisions of the indentures governing its 2017 Senior Notes and the 2018 Senior Notes, LINN redeemed 35%, or $87 million and $90 million, respectively, of each of the original aggregate principal amount of the Original Senior Notes, as defined in Note 6 to LINN’s historical audited financial statementsflows provided by financing activities for the year ended December 31, 2011, included elsewhere in this prospectus.

In March 2011, in connection with its cash tender offers2018 is attributable to borrowings of $429.3 million from our credit facility. Financing activities for the year ended December 31, 2017 were related to capital contributions from Citizen members of $95.6 million and related consent solicitations, LINN also accepted and purchased: (i) $105borrowings of $105.3 million, partially offset by $11.1 million of distributions to Citizen members and repayments of $40.0 million on Citizen’s credit facility.

Analysis of Cash Flow Changes Between the aggregate principal amountYear Ended December 31, 2017 and 2016

Cash flows from operating activities. Cash flows from operating activities for the year ended December 31, 2017 were inflows of its outstanding$60.3 million compared to inflows of $36.1 million for the year ended December 31, 2016. The increase in operating cash flows is primarily related to changes in working capital items and increased revenues partially offset by higher cash expenses.

Cash flows from investing activities. During the year ended December 31, 2017 Senior Notes (or 65%and 2016, we completed acquisitions of the remaining outstanding principal amountoil and natural gas properties of its 2017 Senior Notes), and (ii) $126 million aggregate principal amount of its outstanding 2018 Senior Notes (or 76% of the remaining outstanding principal amount of its 2018 Senior Notes).

In May 2011, LINN issued $750 million in aggregate principal amount of 6.50% senior notes due 2019 and used net proceeds of approximately $729 million to repay all of the outstanding indebtedness under its Credit Facility, to fund or partially fund acquisitions and for general corporate purposes.

In June 2011, LINN repurchased an additional portion of its remaining outstanding 2017 Senior Notes and 2018 Senior Notes for approximately $17 million (or 29% of the remaining outstanding principal amount of its 2017 Senior Notes) and approximately $24 million (or 61% of the remaining outstanding principal amount of its

Index to Financial Statements

2018 Senior Notes), respectively. In December 2011, LINN also repurchased an additional portion of its remaining outstanding 2018 Senior Notes for approximately $2 million (or 9% of the remaining outstanding principal amount of the 2018 Senior Notes). After giving effect to the tender offers and subsequent repurchases of the 2017 Senior Notes and the 2018 Senior Notes, aggregate principal amounts of $41$42.7 million and $14$144.8 million, respectively, remained outstanding atrespectively. Additionally, we invested $167.1 million and $96.3 million during the years ended December 31, 2011.

In March 2012, LINN issued $1.8 billion in aggregate principal amount of 6.25% senior notes due 20192017 and used the net proceeds of the offering to fund the Hugoton Acquisition, to repay indebtedness outstanding under its revolving credit facility and2016, respectively, for general corporate purposes.

LINN depends, in part, on its Credit Facility for future capital needs. In addition, LINN has drawn on the Credit Facility to fund or partially fund quarterly cash distribution payments, since it uses operating cash flow primarily for drilling and development of oil and natural gas properties and acquisitions and borrows as cash is needed. Absent such borrowings, LINN would have at times experienced a shortfall in cash available to pay the declared quarterly cash distribution amount. If an event of default occurs and is continuing under the Credit Facility, LINN would be unable to make borrowings to fund distributions. For additional information about this matter and other risk factors that could affect LINN, please read “Risk Factors.”properties.

Counterparty Credit RiskCash flows from financing activities.

LINN accounts Cash flows from financing activities for its commodity derivatives and, when applicable, its interest rate derivatives at fair value. LINN’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by LINN’s oil, natural gas and NGL reserves; therefore, LINN is not required to post any collateral. LINN does not receive collateral from its counterparties. LINN minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet LINN’s minimum credit quality standard, or have a guarantee from an affiliate that meets LINN’s minimum credit quality standard; and (iii) monitoring the creditworthiness of LINN’s counterparties on an ongoing basis. In accordance with LINN’s standard practice, its commodity derivatives and, when applicable, its interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Equity Distribution Agreement

In August 2011, LINN entered into an equity distribution agreement, pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. In connection with entering into the agreement, LINN incurred expenses of approximately $423,000. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. LINN expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

In September 2011, LINN issued and sold 16,060 units representing limited liability company interests at an average unit price of $38.25 for proceeds of approximately $602,000 (net of approximately $12,000 in commissions). In December 2011, LINN issued and sold 772,104 units representing limited liability company interests at an average unit price of $38.03 for proceeds of approximately $29 million (net of approximately $587,000 in commissions). In connection with the issue and sale of these units, LINN incurred professional service expenses of approximately $139,000. LINN used the net proceeds for general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility.

Index to Financial Statements

In January 2012, LINN issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $1 million in commissions). The net proceeds were used for general corporate purposes including the repayment of a portion of the indebtedness outstanding under LINN’s Credit Facility. At March 31, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.

Public Offering of Units

In March 2011, LINN sold 16,726,067 units representing limited liability company interests at $38.80 per unit ($37.248 per unit, net of underwriting discount) for net proceeds of approximately $623 million (after underwriting discount and offering expenses of approximately $26 million). LINN used a portion of the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Senior Notes and 2018 Senior Notes and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Senior Notes and 2018 Senior Notes. LINN used the remaining net proceeds from the sale of units to finance a portion of the March 31, 2011, acquisition in the Williston Basin.

In January 2012, LINN sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $29 million). LINN used the net proceeds from the sale of these units to repay a portion of the indebtedness outstanding under its Credit Facility.

Unit Repurchase Plan

In October 2008, the Board of Directors of LINN authorized the repurchase of up to $100 million of LINN’s outstanding units from time to time on the open market or in negotiated purchases. In August 2011, LINN repurchased 400,000 units at an average unit price of $32.98 for a total cost of approximately $13 million. In addition, in October 2011, LINN repurchased 129,734 units at an average unit price of $32.08 for a total cost of approximately $4 million.

Distributions

Under LINN’s limited liability company agreement, unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. The following provides a summary of distributions paid by LINN during the year ended December 31, 20112017, were attributable to borrowings of $105.3 million, contributions from Citizen members of $95.6 million, partially offset by $40.0 million repayment of borrowings and $11.1 million of distributions to Citizen members. Financing activities for the year ended December 31, 2016 were related to capital contributions of $169.0 million and $20.0 million of proceeds from borrowings.

Capital Expenditures

Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow and financing under our credit facility.

During the year ended December 31, 2018 and the three months ended March 31, 2012:

Date Paid

  

Period Covered by Distribution

  Distribution
Per Unit
   Total
Distribution
 
          (in millions) 

February 2012

  October 1 – December 31, 2011  $0.69    $138  

November 2011

  July 1 – September 30, 2011  $0.69    $122  

August 2011

  April 1 – June 30, 2011  $0.69    $123  

May 2011

  January 1 – March 31, 2011  $0.66    $116  

February 2011

  October 1 – December 31, 2010  $0.66    $106  

On April 24, 2012, LINN’s Board2019, capital expenditures for drilling and completion costs were $705.2 million and $161.6 million, respectively. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of Directors declaredthese planned capital expenditures depending on a cash distributionvariety of $0.725 per unit, or $2.90 per unit on an annualized basis, with respectfactors, including but not limited to the first quartersuccess of 2012, which represents an increase of 5% over the previous quarter. The distribution, totaling approximately $145 million, was paid on May 15, 2012, to unitholders of record as of the close of business on May 8, 2012.

Index to Financial Statements

Contingencies

LINN has been named as a defendant in a number of lawsuitsour drilling activities, prevailing and is involved in various other disputes arising in the ordinary course of business, including claims from royalty owners related to disputed royalty payments and royalty valuations. LINN has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, LINN has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to LINN. Discovery in this dispute is ongoing and is not complete. As a result, LINN is unable to estimate a possible loss, or range of possible loss, if any. LINN is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

During the years ended December 31, 2011, December 31, 2010, and December 31, 2009, and the three months ended March 31, 2012, LINN made no significant payments to settle any legal, environmental or tax proceedings. LINN regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

In 2008, Lehman Brothers Holdings Inc. and Lehman Brothers Commodity Services Inc. (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, LINN and Lehman entered into Termination Agreements under which LINN was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan (“Plan”) was approved by the Bankruptcy Court. Based on the recovery estimates described in the approved disclosure statement relating to the Plan, LINN expects to ultimately receive a substantial portion of the Company Claim. At March 31, 2012, LINN had a net receivable, which was valued based on market expectations, of approximately $7 million from Lehman Commodity Services related to canceled derivative contracts, and is included in “other current assets” on the consolidated balance sheets. An initial distribution under the Plan of approximately $25 million was received by LINN on April 19, 2012.

Index to Financial Statements

Commitments and Contractual Obligations

The following summarizes, as of December 31, 2011, certain long-term contractual obligations that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes thereto:

   Payments Due 

Contractual Obligations

  Total   2012   2013 – 2014   2015 – 2016   2017 and
Beyond
 
   (in thousands) 

Long-term debt obligations:

          

Credit facility

  $940,000    $—      $—      $940,000    $—    

Senior notes

   3,104,898     —       —       —       3,104,898  

Interest(1)

   2,130,681     268,718     537,436     519,317     805,210  

Operating lease obligations:

          

Office, property and equipment leases

   31,477     5,652     9,367     7,405     9,053  

Other noncurrent liabilities:

          

Asset retirement obligations

   71,142     2,847     3,353     3,438     61,504  

Other:

          

Commodity derivatives

   17,563     14,060     1,772     1,731     —    

Charitable contributions

   222     111     111     —       —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $6,295,983    $291,388    $552,039    $1,471,891    $3,980,665  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1)Represents interest on the Credit Facility computed at the weighted average LIBOR of 2.57% through maturity in April 2016 and interest on the 2019 Senior Notes, 2010 Issued Senior Notes, and the Original Senior Notes, as defined in Note 6 to LINN’s historical audited financial statements for the year ended December 31, 2011, included elsewhere in this prospectus, computed at fixed rates of 11.75%, 9.875%, 6.50%, 8.625% and 7.75% through maturities in May 2017, July 2018, May 2019, April 2020 and February 2021, respectively.

Non-GAAP Financial Measures

The non-GAAP financial measures of adjusted EBITDA and adjusted net income, as defined by LINN, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with income from continuing operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDA and adjusted net income should not be considered in isolation or as a substitute for GAAP measures, such as net income, operating income or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA (Non-GAAP Measure)

Adjusted EBITDA is a measure used by LINN’s management to indicate (prior to the establishment of any reserves by its board of directors) the cash distributions LINN expects to make to its unitholders. Adjusted EBITDA is also a quantitative measure used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

LINN defines adjusted EBITDA as net income (loss) plus the following adjustments:

Net operating cash flow from acquisitions and divestitures, effective date through closing date;

Interest expense;

Depreciation, depletion and amortization;

Index to Financial Statements

Impairment of long-lived assets;

Write-off of deferred financing fees;

(Gains) losses on sale of assets and other, net;

Provision for legal matters;

Loss on extinguishment of debt;

Unrealized (gains) losses on commodity derivatives;

Unrealized (gains) losses on interest rate derivatives;

Realized (gains) losses on interest rate derivatives;

Realized (gains) losses on canceled derivatives;

Unit-based compensation expenses;

Exploration costs;

Income tax (benefit) expense; and

Discontinued operations.

The following table presents a reconciliation of net income (loss) to adjusted EBITDA (unaudited):

   Year Ended December 31,  Three Months Ended
March 31,
 
   2009  2010  2011  2011  2012 
   (in thousands) 

Net income (loss)

  $(298,192 $(114,288 $438,439   $(446,682 $(6,202

Plus:

      

Net operating cash flow from acquisitions and divestitures, effective date through closing date

   3,708    42,846    57,966    7,051    39,093  

Interest expense, cash

   74,185    129,691    249,085    63,590    42,879  

Interest expense, noncash

   18,516    63,819    10,640    (126  34,640  

Depreciation, depletion and amortization

   201,782    238,532    334,084    66,366    117,276  

Impairment of long-lived assets

   —      38,600    —      —      —    

Write-off of deferred financing fees

   204    2,076    1,189    —      1,660  

(Gains) losses on sale of assets and other, net

   (23,051  3,008    124    (823  1,435  

Provision for legal matters

   —      4,362    1,086    492    635  

Loss on extinguishment of debt

   —      —      94,612    84,562    —    

Unrealized (gains) losses on commodity derivatives

   591,379    232,376    (192,951  425,285    53,224  

Unrealized gains on interest rate derivatives

   (16,588  (63,978  —      —      —    

Realized losses on interest rate derivatives

   42,881    8,021    —      —      —    

Realized (gains) losses on canceled derivatives

   (48,977  123,865    (26,752  —      —    

Unit-based compensation expenses

   15,089    13,792    22,243    5,638    8,171  

Exploration costs

   7,169    5,168    2,390    445    410  

Income tax (benefit) expense

   (4,221  4,241    5,466    4,198    8,918  

Discontinued operations

   2,351    —      —      —      —    
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted EBITDA

  $566,235   $732,131   $997,621   $209,996   $302,139  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Index to Financial Statements

Adjusted Net Income (Non-GAAP Measure)

Adjusted net income is a performance measure used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, impairment of long-lived assets, loss on extinguishment of debt and (gains) losses on sale of assets, net.

The following presents a reconciliation of net income (loss) to adjusted net income (unaudited):

   Year Ended December 31,  Three Months Ended
March 31,
 
   2009  2010  2011  2011  2012 
   (in thousands, except per unit amounts) 

Net income (loss)

  $(298,192 $(114,288 $438,439   $(446,682 $(6,202

Plus:

      

Unrealized (gains) losses on commodity derivatives

   591,379    232,376    (192,951  425,285    53,224  

Unrealized gains on interest rate derivatives

   (16,588  (63,978  —      —      —    

Realized (gains) losses on canceled derivatives

   (48,977  123,865    (26,752  —      —    

Impairment of long-lived assets

   —      38,600    —      —      —    

Loss on extinguishment of debt

   —      —      94,612    84,562    —    

(Gains) losses on sale of assets and other, net

   (23,051  2,914    (17  (858  1,400  

Discontinued operations

   2,351    —      —      —      —    
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted net income

  $206,922   $219,489   $313,331   $62,307   $48,422  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Income (loss) from continuing operations per unit—basic

  $(2.50 $(0.80 $2.52   $(2.75 $(0.04

Plus, per unit:

      

Unrealized (gains) losses on commodity derivatives

   4.95    1.63    (1.11  2.62    0.28  

Unrealized gains on interest rate derivatives

   (0.14  (0.45  —      —      —    

Realized (gains) losses on canceled derivatives

   (0.41  0.87    (0.15  —      —    

Impairment of long-lived assets

   —      0.27    —      —      —    

Loss on extinguishment of debt

   —      —      0.54    0.52    —    

(Gains) losses on sale of assets and other, net

   (0.19  0.02    —      (0.01  0.01  

Discontinued operations

   0.02    —      —      —      —    
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted net income per unit—basic

  $1.73   $1.54   $1.80   $0.38   $0.25  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Critical Accounting Policies and Estimates

The discussion and analysis of LINN’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires LINN to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. LINN evaluates its estimates and assumptions on a regular basis. LINN bases estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which

Index to Financial Statements

form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in the preparation of financial statements.

Below are expanded discussions of LINN’s more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of its financial statements.

Recently Issued Accounting Standards

In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The ASU will be applied retrospectively and is effective for periods beginning on or after January 1, 2013. LINN is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

In May 2011, the FASB issued an ASU that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The ASU is to be applied prospectively and is effective for periods beginning after December 15, 2011. The adoption of the requirements of the ASU, which expanded disclosures, had no effect on LINN’s results of operations or financial position.

Oil and Natural Gas Reserves

Proved reserves are based on the quantities of oil, natural gas and NGL that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The independent engineering firm DeGolyer and MacNaughton prepared a reserve and economic evaluation of all of LINN properties on a well-by-well basis as of December 31, 2011, and the reserve estimates reported herein were prepared by DeGolyer and MacNaughton. The reserve estimates were reviewed and approved by LINN’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer.

Reserves and their relation to estimated future net cash flows impact LINN’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, based in part on data provided by LINN. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years.

The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. In addition, reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and NGL eventually recovered. For

Index to Financial Statements

additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in LINN’s historical audited financial statements for the year ended December 31, 2011, included elsewhere in this prospectus.

Oil and Natural Gas Properties

Proved Properties

LINN accountsanticipated prices for oil and natural gas, propertiesthe availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in accordance withresponse to changes in commodity prices and overall market conditions.

Our capital budget for 2019 is $515 million to $555 million. Our capital expenditures are expected to be more heavily weighted to the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining lifefirst half of the proved reserves and proved developed reserves, respectively.year as a result of increased completion activity as we develop our inventory of drilled, uncompleted wells from 2018 drilling activity.

LINN evaluates the impairment of its provedBased upon current oil and natural gas propertiesprices and production expectations for 2019, we believe our cash flow from operations, cash on a field-by-field basis whenever events or changes in circumstances indicate thathand, borrowings under our credit facility and access to capital markets will be sufficient to fund our operations for the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscountednext twelve months. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties.

Working Capital

At March 31, 2019, we had a working capital deficit of $136.6 million compared to $42.2 million at December 31, 2018. Current assets decreased by $68.0 million and current liabilities increased by $26.4 million at March 31, 2019, compared to December 31, 2018. The primary factor contributing to the increase in the working capital deficit is the decrease in the derivative contract assets of $72.8 million, which is due to the negative impact of increases in oil prices on the fair value of our open oil contracts with maturity dates in the next twelve months. Additionally, our accounts payable and accrued expenses have increased due to drilling and completion activities in 2019.

Credit Facility

On September 5, 2017, we entered into our credit facility with Citibank, N.A., as administrative agent, and a syndicate of lenders, which matures on September 5, 2022. Our credit facility, as amended, provides for commitments of $750.0 million, subject to a borrowing base that will be redetermined semi-annually each April 1 and October 1 by the lenders in their sole discretion. As of March 31, 2019, the borrowing base under our existing credit facility was $750.0 million. As of March 31, 2019, we had $602.6 million of borrowings and no letters of credit outstanding under our existing credit facility, with $147.4 million of additional borrowing capacity available. We have and are continuing to evaluate financing options that would enhance our liquidity.

Amounts borrowed under the credit facility bear interest at the London Interbank Offered Rate (“LIBOR”) or the alternate base rate (“ABR”) at our election. The rate sed for ABR loans is based on the higher of the prime rate, the federal funds effective rate plus 0.50% or the one-month LIBOR rate plus 1%. Either rate is adjusted upward by an applicable margin (ranging from 2.00% to 3.00% for LIBOR or 1.00% to 2.00% for ABR), based on the utilization percentage of the credit facility. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50% based on utilization, which is payable at the end of each calendar quarter.

At March 31, 2019, the weighted average interest rate on borrowings under our existing credit facility was 5.25%. We also pay a commitment fee on unused amounts of our existing credit facility of 0.375% to 0.50%. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

Our credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, we are prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon our internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, we are required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per our most recent reserve report.

Our credit facility also requires us to maintain compliance with the following financial ratios:

a leverage ratio, which is the ratio of Consolidated Total Debt (as defined in our credit facility) to Consolidated EBITDAX (as defined in our credit facility) for the rolling four fiscal quarter period ending on the last day of the applicable quarter, of not greater than 4.0 to 1.0; and

a current ratio, which is the ratio of our consolidated current assets (including unused commitments under our credit facility and excludingnon-cash assets under FASB ASC 815 and 410) to our consolidated current liabilities (excluding the current portion of long-term debt under our credit facility,non-cash liabilities under ASC 815 and 410), of not less than net book value. The fair values1.0 to 1.0.

As of proved properties are measured using valuation techniques consistentDecember 31, 2018 and March 31, 2019, we were in compliance with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair valuescovenants under our credit facility.

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of proved propertiesDecember 31, 2018:

   Payments Due by Period 
   2019   2020   2021   2022   2023   Thereafter   Total 
   (in thousands) 

Credit Facility

  $—     $—     $—     $514,639   $—     $—     $514,639 

Interest expense related to Credit Facility (1)

   27,201    27,201    27,201    18,482    —      —      100,085 

Pipe and equipment purchase commitments (2)

   1,455    —      —      —      —      —      1,455 

Office building leases

   1,692    2,047    2,136    2,229    456    171    8,731 

Drilling rig commitments (3)

   15,352    —      —      —      —      —      15,352 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total contractual obligations and commitments

  $45,700   $29,248   $29,337   $535,350   $456   $171   $640,262 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1)

Includes interest expense on our outstanding borrowings calculated using the weighted average interest rate of 5.21% at December 31, 2018. Since December 31, 2018, our outstanding borrowings have increased $88.0 million, which resulted in an increase in the estimated interest expense of $10.0 million based on a weighted average interest rate of 5.25%.

(2)

Reflects commitments to purchase specified amounts of pipe and equipment.

(3)

Reflects future minimum drilling fees including early termination fees as specified by the contract.

The above table does not include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in LINN’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. LINN capitalizes interest on borrowed fundsliabilities related to its share ofARO. These are costs associated with the drillingplugging of wells and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. LINN capitalized interest costs of approximately $2 million, $1 million and $300,000 for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

Impairment of Proved Properties

Based on the analysis described above, LINN recorded no impairment charge of proved oil and natural gas properties for the years ended December 31, 2011, and December 31, 2009. For the year ended December 31, 2010, LINN recorded a noncash impairment charge, before and after tax, of approximately $39 million primarily associated with proved oil and natural gas properties related to an unfavorable marketing contract. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.

Unproved Properties

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair valuesabandonment of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based

Index to Financial Statements

weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. LINN assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as LINN is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. LINN recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million, $5 million and $7 million for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, which are included in “exploration costs” on the consolidated statements of operations.

Revenue Recognition

Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.

LINN has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when LINN sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of LINN’s share is treated as a liability. If LINN receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2011, and December 31, 2010, LINN had natural gas production imbalance receivables of approximately $19 million and $18 million, respectively, which are included in “accounts receivable—trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $9 million and $8 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.

LINN engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, LINN separately reports third-party marketing sales and natural gas marketing expenses.

Asset Retirement Obligations

LINN has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized when the obligation is incurred, and are amortized over proved developed reserves using the unit-of-production method. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations. The fair values of additions to the asset retirement obligations are estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and

Index to Financial Statements

estimates by LINN’s management at the time of the valuation and are the most sensitive and subject to change. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

Derivative Instruments

LINN uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, LINN expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts and put options. A swap contract specifies a fixed price that LINN will receive from the counterparty as compared to floating market prices, and on the settlement date LINN will receive or pay the difference between the swap price and the market price. A put option requires LINN to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. In addition, LINN may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. Currently, LINN has no outstanding derivative contracts in the form of interest rate swaps.

Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. LINN did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. LINN uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets.

Acquisition Accounting

LINN accounts for business combinations under the acquisition method of accounting. Accordingly, LINN recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.

LINN makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair valuesEstimating the future ARO requires management to make estimates and judgments regarding timing and existence of these propertiesa liability that are measured using valuation techniques that convertsubject to future cash flows to a single discounted amount. Significant inputs torevisions based upon numerous factors, including the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average costrate of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. In addition, when appropriate, LINN reviews comparable purchases and sales of oil and natural gas properties within the same regions, and uses that data as a proxy for fair market value; i.e., the amount a willing buyer and seller would enter into in exchange for such properties.

Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill while any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain. Deferred taxes are recorded for any differences between the assigned valuesinflation, changing technology and the tax basis of assetspolitical and liabilities. Estimated deferred taxes are based on available information concerning the tax

regulatory environment.

Index to Financial Statements

basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

While the estimated fair values of the assets acquired and liabilities assumed have no effect on cash flow, they can have an effect on future results of operations. Generally, higher fair values assigned to oil and natural gas properties result in higher future depreciation, depletion and amortization expense, which results in decreased future net earnings. Also, a higher fair value assigned to oil and natural gas properties, based on higher future estimates of commodity prices, could increase the likelihood of impairment in the event of lower commodity prices or higher operating costs than those originally used to determine fair value. The recording of impairment expense has no effect on cash flow but results in a decrease in net income for the period in which the impairment is recorded.

Legal, Environmental and Other Contingencies

A provision for legal, environmental and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts of the accrual is subject to an estimation process that requires subjective judgment of management. In many cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of LINN and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. LINN’s management closely monitors known and potential legal, environmental and other contingencies and periodically determines when it should record losses for these items based on information available to LINN.

Unit-Based Compensation

LINN recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based payments granted to employees and nonemployee directors.

Quantitative and Qualitative DisclosuresDisclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodityoil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how LINN views and manages its ongoing market risk exposures. All of LINN’sour market risk sensitive instruments were entered into for purposes other than speculative trading.

The following should be read in conjunction with the financial statements and related discussion included elsewhere in this registration statement.

Commodity Price Risk

LINN enters into derivativeThe following table provides a summary of our open commodity contracts with respectat March 31, 2019:

   2019   2020   Total 

Oil fixed prices swaps

      

Volume (Bbl)

   3,874,890    3,063,500    6,938,390 

Weighted-average price

  $60.05   $60.74   $60.36 

Natural gas fixed price swaps

      

Volume (MMBtu)

   30,442,000    16,005,000    46,447,000 

Weighted-average price

  $2.91   $2.64   $2.82 

Natural gas basis swaps

      

Volume (MMBtu)

   22,000,000    7,320,000    29,320,000 

Weighted-average price

  $0.60   $0.53   $0.58 

Natural gas liquids fixed price swaps

      

Volume (MMBtu)

   825,000    —      825,000 

Weighted-average price

  $32.25   $—     $32.25 

We are exposed to a portion of its projected production through various transactions that provide an economic hedge of themarket risk related to the future commoditychanges in the pricing applicable to our oil, natural gas and NGLs production. The prices received. LINN does not enter into derivativeof our commodities are subject to fluctuations resulting from changes in supply and demand. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future.

We use derivatives, including fixed price swaps and basis swaps, to reduce price volatility associated with certain of our oil and natural gas sales. With respect to these fixed price swap contracts, for trading purposes (see Note 7 to LINN’s historical audited financial statements forwhen the year ended December 31, 2011, included elsewherereference settlement price is less than the price specified in this prospectus).the contract, we receive an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, we pay the counterparty an amount based on the price difference multiplied by the volume.

At March 31, 2012,2019, we had a net asset position of $12.8 million related to our derivative contracts. Utilizing actual derivative contractual volumes under our fixed price swaps as of March 31, 2019 an increase of 10% in the forward curves associated with the underlying commodity would have changed our net asset position to a net liability position of $40.3 million, while a decrease of 10% in the forward curves associated with the underlying commodity would have increased the net asset position to $69.9 million.

Credit Risk

Our principal exposure to credit risk is through the sale of our oil, natural gas and NGLs production, which we market to energy marketing companies and refineries, and to a lesser extent, our derivative counterparties.

We are subject to credit risk resulting from the concentration of our oil, natural gas and NGLs receivables with two significant purchasers. We do not believe the loss of any single purchaser would materially impact its results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.

Our derivative transactions have been carried out in theover-the-counter market. The entry into derivative transactions in theover-the-counter market involves the risk that the counterparties, which are financial institutions, may be unable to meet the financial terms of the transactions. We monitor on an ongoing basis the credit ratings of our derivative counterparties and consider their credit default risk ratings in determining the fair value of fixed price swapsour derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. The counterparties to our derivative contracts at March 31, 2019 are also lenders under our credit facility. As a result, we do not require collateral or other security from counterparties nor are we required to

post collateral to support derivative instruments. We have master netting agreements with all of our derivative counterparties, which allow us to net our derivative assets and putliabilities with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our credit facility. The terms of our credit facility provide for interest on borrowings at LIBOR or the alternate base rate, in each case adjusted upward by an applicable margin based on the utilization percentage of the credit facility.

At March 31, 2019, we had $602.6 million of debt outstanding, with a weighted average interest rate on these borrowings of 5.25%. Interest is calculated under the terms of our existing credit facility based on certain specified base rates plus an applicable margin that varies based on utilization. Interest is calculated under our existing term loan facility based on certain specified base rates plus an applicable margin. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be $6.0 million per year.

Critical Accounting Policies and Estimates

The financial statements reflect a number of significant estimates that impact the carrying values of assets and liabilities and reported amounts of revenue and expenses. We make these estimates based on historical experience and on other judgments and assumptions that we believe are reasonable under the circumstances. The results of these estimates, judgments and assumptions form the basis for our determinations as to the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We consider an accounting policy to be critical when it requires the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are highly uncertain. We believe that the following critical accounting policies reflect our more significant estimates and assumptions used in the preparation of our financial statements.

Recently Issued Accounting Standards

For a discussion of recently issued accounting standards, please see Note 3 to the audited financial statements.

Reserves

Proved reserves are based on the quantities of oil, natural gas and NGL that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that settle duringrenewal is reasonably certain. Our proved reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers and our internal staff. DeGolyer and MacNaughton prepared reserve estimates for 93% of our total reserves.

Estimates of proved oil, natural gas and NGL reserves are used in the next 12 months wascalculation of depletion of our oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. As a result, changes in estimated quantities of our proved reserves could impact our reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. The process performed by the

independent engineers to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data we provided. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years.

The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various economic assumptions and the judgments of the individuals preparing the estimates. In addition, reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and NGL eventually recovered.

Revenue Recognition

Revenues from the sale of oil, natural gas and NGLs are recognized when control of the product has transferred to the customer, all performance obligations have been satisfied and collectability is reasonably assured. We recognize revenues from the sale of oil, natural gas and NGLs based on our share of volumes sold. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make up the overproduced (or under produced) imbalance.

We adopted ASU2014-09, ASC 606 on January 1, 2018 using a modified retrospective transition approach whereby changes have been applied for periods commencing after December 31, 2017 and prior period results have not been adjusted to conform to current presentation.

Under the new rules, revenues and transportation expenses associated with the natural gas and NGL production from our operated properties are now reported on a net assetbasis compared to gross presentation in our historical periods. Fornon-operated properties, we receive a net payment from the operator for our share of approximately $323 million. A 10% increasesales proceeds which is net of transportation costs incurred by the operator, if any. Suchnon-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice.

Business Combinations

We account for all business combinations using the acquisition method, which involves the use of significant judgment. In a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill.

We estimate the fair values of assets acquired and liabilities assumed in a business combination using various assumptions (all of which are predominantly Level 3 inputs within the fair value hierarchy). The most significant assumptions typically relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of the proved and unproved oil and natural gas properties, we develop estimates of oil, natural gas and NGL reserves. Estimates of reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Additionally, a risk factor is applied to reserves by reserve type based on industry standards. We estimate future prices to apply to the estimated net quantities of reserves based on the applicable ownership percentage acquired and estimates future operating and development costs to arrive at estimates of future net cash flows. The future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition.

Oil and Natural Gas Properties

We follow the successful efforts method to account for our exploration and production activities. Under this method, costs incurred to purchase, lease, or otherwise acquire a property, whether unproved or proved, are capitalized when incurred. We initially capitalize exploratory well costs pending a determination whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells.

Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed as incurred. Additionally, costs to operate and maintain wells and field equipment are expensed as incurred.

Depletion of capitalized drilling and development costs of producing oil and natural gas properties are computed using theunit-of-production method on a field level basis, based on total estimated proved developed oil, natural gas and NGL reserves. We determined our oil and natural gas properties are comprised of one single field. Proved leasehold costs associated with proved reserves are depleted based on total proved reserves, which includes proved undeveloped reserves. Under theunit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property.

The net carrying values of retired, sold or abandoned proved properties that constitute less than a complete unit of depletable property are charged, net of proceeds, to accumulate depreciation, depletion and amortization unless doing so significantly affect theunit-of-production amortization rate, in which case a gain or loss is recognized to earnings. Gains or losses from the disposal of complete units of depletable property are recognized in earnings.

Proceeds from sales of all or a partial interest in individual unproved properties assessed for impairment on a group basis are accounted for as a recovery of costs. No gain or loss is recognized unless the sales proceeds exceed the original cost of the entire interest in the indexproperty, in which a gain will be recognized for the excess.

Impairment of Oil and Natural Gas Properties

Proved oil and natural gas properties are evaluated for impairment when facts or circumstances indicate that the carrying value of those assets may not be recoverable, such as when there are declines in oil and natural gas prices aboveor well performance. In performing this assessment, assets are grouped at the March 31, 2012, priceslowest level for which there are identifiable cash flows that are largely independent of the next 12 months would result in a netcash flows of other groups of assets. An impairment loss is indicated if the sum of the estimated undiscounted future cash flows related to an asset group is less than the carrying value of approximately

that asset group. If an impairment loss has been incurred, the loss recognized is the excess of the carrying amount over the estimated fair value.

Index to Financial Statements

$171 million which represents a decrease inWe calculate the estimated fair value using a discounted future cash flow model. Management’s assumptions associated with the calculation of approximately $152 million; conversely, a 10% decrease in the indexfuture cash flows include oil and natural gas prices wouldbased on NYMEX futures price strips, as well as other assumptions, including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes, (v) timing of development, and (vi) estimated reserves. A discount rate, consistent with that used by market participants, is applied to the estimated future cash flows in order to estimate fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) oil and natural gas futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, and (iv) results of future drilling activities.

Our unproved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictated that the carrying value of those assets may not be recoverable. Unproved leasehold costs are amortized on a group basis if individually insignificant, and a valuation allowance is established with a monthly amortization charge to exploration expense for the portion of the properties’ total cost that management estimates may never be transferred to proved properties during the terms of the respective leases. The impairment amortization rate considers our current drilling plans, the remaining terms of the respective leases and the results of exploratory drilling activity, and can be affected by economic factors including oil and natural gas price outlooks, projected capital costs, and available liquidity.

Costs of expired or relinquished leases are charged against the valuation allowance.

Derivative Instruments

We have entered into commodity derivative instruments to reduce the effect of price changes on a portion of our future oil and natural gas production.

The commodity derivative instruments are measured at fair value and are included in the balance sheet as derivative assets and derivative liabilities, on a net basis by counterparty. We adjust the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of our commodity derivative instruments are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. We have not designated any of the derivative contracts as fair value or cash flow hedges for accounting purposes for any of the periods presented. Accordingly, net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments and are included in gain (loss) on derivative contracts in the consolidated statements of operations. Our cash flow is impacted when the settlements under the commodity derivative contracts result in making or receiving a net assetpayment to or from the counterparty and are reflected as operating activities in our consolidated statements of approximately $480 million which represents an increase incash flows. Our firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not requiremark-to-market accounting treatment.

Equity-Based Compensation

In December 2017 and during 2018 prior to the Reorganization, we granted certain employees performance share units (“PSUs”) pursuant to the Roan Resources LLC Management Incentive Plan (the “MIP”). PSUs issued under the MIP were recognized as equity awards based on their characteristics. The compensation measurement was based on the grant date fair value of the award. The fair value of the PSUs is determined at the date of grant and is not remeasured. We determined the fair value of approximately $157 million.

Interest Rate Risk

At March 31, 2012, LINN had long-term debt outstanding under its Credit Facilitythe PSUs based on an estimate of approximately $75 million, which incurred interest at floating rates. A 1% increase in the London Interbank Offered Rate (“LIBOR”) would result in an estimated $1 million increase in annual interest expense.

Counterparty Credit Risk

LINN accounts for its commodity derivatives and, when applicable, its interest rate derivatives at fair value on a recurring basis (see Note 8 to LINN’s historical audited financial statements for the year ended December 31, 2011, included elsewhere in this prospectus). The fair value of these derivative financial instruments includesour equity using an income approach. We used a discounted cash flow method to value the impact of assumed credit risk adjustments, which are basedestimated future cash flows at an appropriate discount rate. For PSUs, compensation value is measured on LINN’s and its counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.

At March 31, 2012, the average public bond yield spread utilized to estimate the impact of LINN’s credit risk on derivative liabilities was approximately 4.21%. A 1% increasegrant date using payout values derived from a Monte-Carlo valuation model. Estimates used in the average public bond yield spread would resultMonte Carlo valuation model are considered highly complex and subjective. For equity awards issued subsequent to the reorganization transactions, we will utilize the trading price of our shares. Equity compensation is recognized over the requisite service period. For employees directly involved in an estimated $150,000 increaseexploration and development activities, equity compensation is capitalized to our oil and natural gas properties. Equity compensation not capitalized is recognized in net income forgeneral and administrative expenses or production expense in the three months ended March 31, 2012. At March 31, 2012, the credit default swap spreads utilized to estimate the impactstatements of its counterparties’ credit risk on derivative assets ranged between 0.00% and 4.01%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $4 million decrease in net income for the three months ended March 31, 2012.operations.

Index to Financial Statements

BUSINESSIncome Taxes

LinnCo

We areRoan LLC was organized as a Delaware limited liability company formed in Delaware in April 2012. Upon completion of this offering, our only business will consist of owning LINN units. We will have no operations prior to the closing of this offering. As a result, our financial condition and results of operations following this offering will depend entirely upon the performance of LINN. We do not expect to have any income or cash flow other than distributions we receive in respect of our LINN units. When LINN makes distributions on the units, we will pay a dividend on our shares of the cash we receive in respect of our LINN units, net of reserves for income taxes payable by us. For the periods ending December 31, 2012, 2013, 2014 and 2015, we estimate that our income tax liability will not exceed     % of the cash distributed to us. On April 24, 2012, LINN declared a regular quarterly cash distribution of $0.725 per unit, or $2.90 per unit on an annualized basis. Accordingly, if LINN were to maintain its current annualized distribution of $2.90 per unit through 2015, the amount reserved to pay income taxes of LinnCo is estimated to be no more than $         per share for the periods ending December 31, 2012, 2013, 2014 and 2015.

We have elected to be treated as a corporationflow-through entity for U.S. federal income tax purposes. As a result, an owner of our shares will not report onRoan LLC has historically passed through its taxable income to its owners for U.S. federal, state and local income tax return any of our items of income, gain, losspurposes and, deduction, nor will they receive a Schedule K-1. Our shareholders also willthus, was not be subject to state income tax filings in the various states in which LINN conducts operations as a result of owning our shares. Like shareholders of a corporation, our shareholders will be subject to U.S. federal income tax, as well as any applicabletaxes, state or local income taxes. Accordingly, no tax provision was made in the financial statements of Roan LLC since the income tax was an obligation of its members.

Following the Reorganization, Roan Inc. is now taxed as a corporation. Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on taxable dividends received by them. Please read “Materialour results of operations for the years ended December 31, 2018, 2017 or 2016. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. Federal Income Tax Consequences” for additional details.

LINN

Overview

LINN’s mission iseconomy and we tend to acquire, developexperience inflationary pressure on the cost of oilfield services and maximize cash flow from a growing portfolio of long-lifeequipment as increasing oil and natural gas assets. LINN isprices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

We enter into certainoff-balance sheet arrangements and transactions, including operating lease arrangements and undrawn letters of credit. We do not have any outstanding letters of credit. In addition, we enter into other contractual agreements in the normal course of business for processing and transportation as well as for other oil and natural gas activities. Other than the items discussed above, there are no other arrangements, transactions or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or capital resource positions.

BUSINESS

Our Company

We are an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering (“IPO”) in January 2006. LINN’s properties are located in the United States, primarily in the Mid-Continent, Hugoton Basin, Green River Basin, Permian Basin, Michigan/Illinois, California, Williston/Powder River Basin, and East Texas.

Proved reserves at December 31, 2011, were 3,370 Bcfe, of which approximately 34% were oil, 50% were natural gas and 16% were natural gas liquids (“NGL”). Approximately 60% were classified as proved developed, with a total standardized measure of discounted future net cash flows of $6.6 billion. At December 31, 2011, LINN operated 7,759 or 69% of its 11,230 gross productive wells and had an average proved reserve-life index of approximately 22 years, basedfocused on the December 31, 2011, reserve report and fourth quarter 2011 annualized production.

Recent Developments

Anadarko Joint Venture

On April 3, 2012, LINN entered into a joint venture agreement with an affiliate of Anadarko whereby LINN will participate as a partner in the CO2-enhanced oil recovery development of our assets throughout the Salt Creek field, located ineastern and southern Anadarko Basin. The Anadarko Basin, which spans from south-central Oklahoma to the Powder River Basin of Wyoming. Anadarko assigned LINN 23% of its interest in the field in exchange for future funding by LINN of $400 million of Anadarko’s development costs. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves asnortheast corner of the agreement date based on LINN’s preliminary internal evaluation.

Acquisitions

On June 21, 2012, LINN entered into a purchase agreement for certain oil and natural gas properties located in the Green River Basin area of southwest Wyoming for a contract price of approximately

Index to Financial Statements

$1.025 billion. LINN anticipates the acquisition will close on or before July 31, 2012, and will be financed with the proceeds from borrowings under its revolving credit facility. In addition to customary closing conditions, the acquisition is subject to a preferential right of purchase that encompasses substantially all of the properties. The expiry period for waiver or acceptance of the preferential right of purchase is anticipated during the first week of July 2012. The pending acquisition includes approximately 753 Bcfe of estimated proved reserves. The estimated proved reserves for the pending acquisition were based on LINN’s preliminary internal evaluation of information provided by the seller

On May 1, 2012, LINN completed the acquisition of properties located in east Texas for total consideration of approximately $168 million. The acquisition included approximately 110 Bcfe of proved reserves as of the acquisition date.

On March 30, 2012, LINN completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin area of southwestern Kansas for total consideration of $1.17 billion. The acquisition included approximately 701 Bcfe of proved reserves as of the acquisition date.

Proved reserves as of the acquisition date for all of the above referenced acquisitions were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.

LINN regularly engages in discussions with potential sellers regarding acquisition opportunities. Such acquisition efforts may involve its participation in auction processes, as well as situations in which LINN believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts can involve assets that, if acquired, would have a material effect on its financial condition and results of operations.

Distributions

On April 24, 2012, LINN’s Board of Directors declared a cash distribution of $0.725 per unit, or $2.90 per unit on an annualized basis, with respect to the first quarter of 2012, which was paid on May 15, 2012 to unitholders of record at the close of business May 8, 2012.

On January 27, 2012, LINN’s Board of Directors declared a cash distribution of $0.69 per unit, or $2.76 per unit on an annualized basis, with respect to the fourth quarter of 2011. The distribution, totaling approximately $138 million, was paid on February 14, 2012, to unitholders of record as of the close of business on February 7, 2012.

Operating Regions

As of December 31, 2011, LINN’s properties were located in six operating regions in the U.S.:

Mid-Continent Deep, which includes the Texas Panhandle Deep Granite Wash formation and deep formations in Oklahoma and Kansas;

Mid-Continent Shallow, which includes the Texas Panhandle Brown Dolomite formation and shallow formations in Oklahoma, Louisiana and Illinois;

Permian Basin, which includes areas in West Texas and Southeast New Mexico;

Michigan, which includes the Antrim Shale formation in the northern part of the state;

California, which includes the Brea Olinda Field of the Los Angeles Basin; and

Williston Basin, which includes the Bakken formation in North Dakota.

Mid-Continent Deep

The Mid-Continent Deep region includes properties in the Deep Granite Wash formation in the Texas Panhandle, which produces at depths ranging from 10,000 feet to 16,000 feet, as well as properties in Oklahoma and Kansas, which produce at depths of more than 8,000 feet. Mid-Continent Deep proved reserves represented

Index to Financial Statements

approximately 47% of total proved reserves at December 31, 2011, of which 49% were classified as proved developed reserves. This region produced 172 MMcfe/d or 47% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $268 million to drill in this region. During 2012, LINN anticipates spending approximately 65% of its total oil and natural gas capital budget for development activities in the Mid-Continent Deep region, primarily in the Deep Granite Wash formation.

To more efficiently transport its natural gas in the Mid-Continent Deep region to market, LINN owns and operates a network of natural gas gathering systems comprised of approximately 285 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the Texas Panhandle.

Mid-Continent Shallow

The Mid-Continent Shallow region includes properties producing from the Brown Dolomite formation in the Texas Panhandle, which produces at depths of approximately 3,200 feet, as well as properties in Oklahoma, Louisiana and Illinois, which produce at depths of less than 8,000 feet. Mid-Continent Shallow proved reserves represented approximately 20% of total proved reserves at December 31, 2011, of which 70% were classified as proved developed reserves. This region produced 63 MMcfe/d or 17% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $9 million to drill in this region. During 2012, LINN anticipates spending approximately 2% of its total oil and natural gas capital budget for development activities in the Mid-Continent Shallow region.

To more efficiently transport its natural gas in the Mid-Continent Shallow region to market, LINN owns and operates a network of natural gas gathering systems comprised of approximately 665 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the Texas Panhandle.

Permian Basin

The Permian Basinpanhandle, is one of the largest and most prolific onshore oil and natural gas basins in the U.S. LINN’s properties are locatedUnited States, featuring multiple producing horizons and extensive well production history demonstrated over seven decades of development. We focus our development on formations where we believe we can apply our technical and operational expertise in West Texasorder to increase production and Southeast New Mexicocash flow. Our objective is to maximize shareholder value and produce at depths ranging from 2,000 feet to 12,000 feet. Permian Basincorporate returns by generating steady production growth, strongpre-tax margins and significant cash flow.

Through December 31, 2018, we and our predecessors have drilled 214 gross (72 net) wells in the Merge, SCOOP and STACK plays. Our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs, and provides us development opportunities through multiple stacked prospective development horizons. We believe these development horizons have been substantiallyde-risked through the development of more than 400 horizontal wells since early 2014, of which 152 were drilled by us or our predecessors, and over 4,450 vertical wells drilled in our development area, as well as associated subsurface data, including well cores and logs and3-D seismic and the consistent geology surrounding our position. As of December 31, 2018, we operated 163 gross (131 net) horizontal producing wells and had an interest in an additional 317 gross (19 net) horizontal producing wells.

As of December 31, 2018, we held leasehold interests in approximately 383,000 gross (172,000 net) acres in the Anadarko Basin. As of December 31, 2018, our total estimated proved reserves representedwere approximately 16% of total proved reserves at December305,959 MBoe. For the quarter ended March 31, 2011, of which 56% were classified as proved developed reserves. This region produced 73 MMcfe/2019, our average net daily production was 48.9 MBoe/d or 20% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $255 million to drill in this region. During 2012, LINN anticipates spending approximately 25% of its total(approximately 26% oil, and44% natural gas capital budgetand 30% NGLs).

We have chosen to focus our development efforts on the Merge play, as we believe it benefits from the following attributes:

Stacked Formations. The Merge has been proven to be prospective for two primary resource formations: the Mayes (Meramec/Sycamore equivalent) formation and the Woodford formation. We and our predecessors have demonstrated successful economic development activities in the Permian Basin region, primarily in the Wolfberry trend.

Michigan

The Michigan region includes propertiesof both benches, with 63 gross (53 net) and 80 gross (65 net) horizontal operated wells producing from the Antrim Shale formation in the northern part of the state, which produces at depths ranging from 600 feet to 2,200 feet. Michigan proved reserves represented approximately 9% of total proved reserves at December 31, 2011, of which 90% were classified as proved developed reserves. This region produced 35 MMcfe/d or 9% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $3 million to drill in this region. During 2012, LINN anticipates spending approximately 1% of its total oilMayes and natural gas capital budget for development activities in the Michigan region.

California

The California region consists of the Brea Olinda Field of the Los Angeles Basin. The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths ranging from 1,000 feet to 7,500 feet. California proved reserves represented approximately 6% of total proved reserves at December 31, 2011, of which 93% were classified as proved developed reserves. This region produced 14 MMcfe/d or 4% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $6 million to drill in this region. During 2012, LINN anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the California region.

Index to Financial Statements

Williston Basin

The Williston Basin is one of the premier oil basins in the U.S. LINN’s properties are located in North Dakota and produce at depths ranging from 9,000 feet to 12,000 feet. Williston Basin proved reserves represented approximately 2% of total proved reserves at December 31, 2011, of which 48% were classified as proved developed reserves. This region produced 12 MMcfe/d or 3% of LINN’s 2011 average daily production. During 2011, LINN invested approximately $39 million to drill in this region. During 2012, LINN anticipates spending approximately 6% of its total oil and natural gas capital budget for development activities in the Williston Basin region.

Drilling and Acreage

The following sets forth the wells drilled in the Mid-Continent Deep, Mid-Continent Shallow, Permian Basin, Michigan, California and Williston Basin operating regions during the periods indicated (“gross” refers to the total wells in which LINN had a working interest and “net” refers to gross wells multiplied by LINN’s working interest):

   Year Ended December 31, 
   2009   2010   2011 

Gross wells:

      

Productive

   72     138     292  

Dry

   1     1     2  
  

 

 

   

 

 

   

 

 

 
   73     139     294  
  

 

 

   

 

 

   

 

 

 

Net development wells:

      

Productive

   35     116     186  

Dry

   1     1     2  
  

 

 

   

 

 

   

 

 

 
   36     117     188  
  

 

 

   

 

 

   

 

 

 

Net exploratory wells:

      

Productive

   —       —       —    

Dry

   —       —       —    
  

 

 

   

 

 

   

 

 

 
   —       —       —    
  

 

 

   

 

 

   

 

 

 

The totals above do not include 8 and 25 lateral segments added to existing vertical wellbores in the Mid-Continent Shallow region during the years ended December 31, 2010, and December 31, 2009, respectively. There were no lateral segments added to existing vertical wellbores during the year ended December 31, 2011. At December 31, 2011, LINN had 85 gross (51 net) wells in process (no wells were temporarily suspended).

This information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and the quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of oil, natural gas or NGL, regardless of whether they generate a reasonable rate of return.

The following sets forth information about LINN’s drilling locations and net acres of leasehold interestsWoodford formations, respectively, as of December 31, 2011:2018.

Reservoir Quality. Reservoir characteristics from petrophysical analysis demonstrate high porosity and permeability development in the Merge as compared to other unconventional plays.

Phase Window Positioning. The thermal maturity of the source rock throughout the eastern portion of the Merge results in production profiles characterized by high percentages of oil and NGLs. Specifically, over 80% of our operated acreage is within areas we believe demonstrate higher percentage production of oil and NGLs within the Merge play.

Pressure Gradients. Geopressure across our operated acreage position in the Merge play ranges from slightly to significantly overpressured at approximately 0.45 to 0.65 pounds psi per foot of true vertical depth, resulting in superior well deliverability and improved GOR trend stability as compared to normal to under-pressured reservoirs.

As of December 31, 2018, we had assembled a total leasehold position of approximately 172,000 net acres, which is predominantly concentrated in the Merge and SCOOP plays. In addition to the subsurface benefits of our position, we believe our acreage position benefits from the following characteristics:

High Degree of Operational Control.We expect that we will be able to control operations on approximately 71% of our acreage in the Merge, SCOOP and STACK plays. For these purposes, we have assumed that we will control any unit in which we have leased a minimum of 37.5% of the acreage in the unit. Operational control of our leasehold positions allows us to control the development and production methods, as well as the pace of development on our wells.

Contiguous Acreage Position.A substantial portion of the sections in which we have operational control are offset to the north or south by adjacent controlled sections. Specifically, approximately 66% of our sections in the Merge, SCOOP and STACK plays can be developed on a multi-unit basis. As a result, we are able to develop long lateral horizontal wells for the majority of our drilling program, which we believe have exhibited superior economics as compared to shorter laterals as a result of development cost efficiencies.

LargelyHeld-by-Production.Approximately 84% of our total acreage position was HBP as of December 31, 2018. We expect this high percentage of HBP acreage to enhance capital efficiencies in our development program, as we will pursue development locations with the favorable risk-adjusted rates of return in our location selection process, as opposed to selecting locations in order to hold acreage.

The table below provides a summary of our acreage position as of December 31, 2018:

 

   Total(1)Total 

Proved undevelopedOperated Sections

   2,302313 

Other locationsOperated Acres

   4,154122,254

Non-Operated Acres

49,717 
  

 

 

 

Total drilling locationsAcres

   6,456171,970

% HBP

84

% Operated

71

Our Drilling Program and Completion Techniques

We intend to target accretive growth in production and cash flow by developing and expanding our significant portfolio of drilling locations. We believe that our recent well results demonstrate that many of our development projects are capable of producing attractive rates of return that are competitive with many of the top performing basins in the United States. We are focused on drilling wells with high rates of return, repeatable production profiles and increasing EURs while at the same time seeking to capitalize on drilling, completion and operating efficiencies. Our management team assumed operation of our properties in the first half of 2018 and has achieved meaningful operational advancements, including (i) improvement in lateral targeting, (ii) reductions in development cycle times, (iii) optimization testing of well completion methods, (iv) well flowback management, and (v) expanded subsurface data coverage, including3-D seismic.

Reserves Information

The following table provides summary information regarding our proved reserves as of December 31, 2018, based on a reserve report prepared by DeGolyer and MacNaughton,our independent reserve engineers.

Estimated Total Proved Reserves
Oil
(MMBbls)
  NGLs
(MMBbls)
  Natural
Gas (Bcf)
  Total
(MMBoe)
  PV-10
($)(1)(2)
  %
Oil
  %
Liquids
  %
Developed
55.7  98.4  911.2  306.0  2,091,509  18.2  50.4  39.3

(1)

Presented in thousands.PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Please see “Risk Factors—The standardized measure of our estimated reserves contained in this prospectus and in the footnotes to our financial statements is not an accurate estimate of the current fair value of our estimated reserves.” NeitherPV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry usePV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Please see “Summary Historical and Unaudited Pro Forma FinancialData—Non-GAAP FinancialMeasure—PV-10”.

(2)

Our estimated net proved reserves were determined using averagefirst-day-of-the-month prices for the prior 12 months in accordance with SEC guidance adjusted for quality, transportation fees, regional price differentials, and in the case of natural gas, energy content. For oil and NGLs volumes, the average WTI posted price of $65.66 per barrel as of December 31, 2018, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $3.16 per MMBtu as of December 31, 2018, was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.49 per barrel of oil, $20.35 per barrel of NGLs and $1.90 per Mcf of natural gas as of December 31, 2018.

Our Business Strategies

Our primary objective is to maximize shareholder value across business cycles by pursuing the following strategies:

Generate attractive full-cycle returns through the efficient development of our extensive,low-risk drilling inventory.We intend to efficiently achieve industry leading rates of return by leveraging the scale of our core leasehold positions, experience from the success of our drilling program to date, technical understanding of the reservoirs, our extensive catalogue of technical information and experience of our operational teams. We intend to allocate capital in a disciplined manner to projects that we believe will produce predictable and attractive full-cycle rates of return. We consider our extensive inventory of high-potential, oil and liquids-weighted drilling locations to be relativelylow-risk based on information gathered from over 400 horizontal wells developed since early 2014, of which 152 were drilled by us or our predecessors, and over 4,450 vertical wells developed in our development area, industry activity surrounding our acreage, subsurface data, including well cores and logs and3-D seismic and the consistent geology surrounding our position.

Maximize value of our asset base through constant focus on improving operating, production and capital efficiencies.We utilize proprietary data analytics, combined with operational procedures and metrics, to evaluate well results and adjust drilling and production techniques in real time. We use this framework in an effort to maximize hydrocarbon recoveries per well by optimizing location selection, wellbore targeting, well completion designs and production techniques.Our management and technical teams intend to apply their operational expertise, data gained from our large acreage position in the Merge play and available third-party data to deploy advanced drilling, completion and production management technologies that maximize well productivity and control capital and operating costs. Additionally, we seek to reduce capital and operating costs of drilling and completing horizontal wells by decreasing development cycle times, optimizing the use of surface facilities, capitalizing on our knowledge of the target formations and focusing on service cost management practices. Our highly experienced management and technical teams have a substantial track record of developing unconventional plays, which we believe is instrumental in our achievement of these operational and capital efficiencies.

Maintain a high degree of operational control to facilitate efficient development and capital budgeting.We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As of December 31, 2018, we operated approximately 71% of our total acreage. We believe that maintaining a high degree of control of the development of our properties and of our production enables us to increase hydrocarbon recovery rates, lower capital and operating costs and improve drilling performance through optimization of our drilling, completion and production management techniques. Additionally, we believe operatorship allows us to control wellsite selection, spacing and lateral targeting and manage the pace of our development activities, which we believe can significantly enhance full-cycle returns. We will adjust the size of our rig program to optimize our overall development program and with a view to limiting the lag time between the development of parent and child wells. Through these measures, we seek to target an optimal combination of net present value and rate of return associated with the development of a particular unit. According to RS Energy Group, child wells are generally at least 25% more productive if drilled within 1.5 years of the development of the parent well, as compared to child wells drilled 1.5 to 3 years following the development of the parent well. Operational and developmental control positions us to minimize the adverse impacts associated with this time lag.

Maintain a disciplined, returns-driven strategy with a focus on maintaining financial flexibility.We intend to maintain a conservative financial profile that will afford us flexibility through the commodity price and capital market cycles inherent in the oil and natural gas industry. We intend to generate stable production and reserves growth by funding our development program primarily with cash flow from operations, borrowings under our credit facility and capital markets offerings. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price volatility, enabling us to protect future cash flows and maintain liquidity to fund our development program.

Selectively pursue opportunities to augment our asset base through the disciplined acquisition or leasing of oil and natural gas properties. We believe we are well positioned to selectively pursue accretive consolidation opportunities. We believe the strength of our operational program provides a competitive advantage in the pursuit of such opportunities. We will continue to identify and evaluate acquisition and leasing opportunities around and within our concentrated acreage position, as well as other areas in Oklahoma, that meet our strategic and financial objectives.

Our Competitive Strengths

We believe the following strengths will allow us to successfully execute on our business strategies:

Large, contiguous acreage position in the core of the Merge play with significant operational control.We are the largest leaseholder in the Merge play, with approximately 115,000 net acres as of December 31, 2018. We believe that the scale and concentration of our acreage position allows for efficient field development through long laterals and shared facilities, with approximately 80% of our Merge sections capable of 1.5 mile or longer lateral development. Additionally, our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs within the Merge play, and provides us development opportunities through multiple stacked prospective development horizons. As of December 31, 2018, we operated 81% of our net acreage in the Merge and we intend to maintain operational control over the majority of our drilling inventory, as we believe this enables us to increase our production and reserves and control our development costs, and ultimately increase shareholder value. Operatorship of our position allows us the flexibility to control the pace of our development plan, as well as the lengths of our laterals and our drilling and well completion techniques.

Long-lived inventory of locations with predictable production profiles that provide highrate-of-return development opportunities.Through the drilling of over 163 operated horizontal wells and participation in over 317non-operated horizontal wells as of December 31, 2018 across our

acreage, we have substantially delineated our acreage and have acquired significant amounts of subsurface information. Based on this delineation and general industry Merge, SCOOP and STACK well production history, we believe that our acreage position will provide a large portfolio of drilling locations characterized by long-lived reserves, predictable production profiles and attractive return potential.

Geographically advantaged assets with significant available midstream infrastructure and favorable regulatory climate.Our acreage position is in close proximity or has available access to end markets for oil, natural gas and NGLs, providing us with a regional price advantage relative to other U.S. onshoreoil-weighted basins. While oil represents a significant portion of our total revenues, natural gas and NGLs comprise a majority of our reserves and production. While we believe we have favorable realized price differentials for natural gas and NGLs compared to other basins, our realized natural gas price differential is based on the sales price at multiple hubs and our NGLs are sold on a product by product basis. Oklahoma has a long history of oil and natural gas production, and therefore there is existing midstream infrastructure in place across our acreage position to support our drilling program. In addition, we believe that oilfield services availability is greater in our focus area than in other major U.S. onshore basins and that such availability is a competitive advantage in assuring the ability to access necessary development services at attractive pricing.

Experienced operations leadership with substantial technical expertise. We believe our operational management team provides us with a distinct competitive advantage. Our team has significant experience working together throughout theMid-Continent and evaluating the Merge play in particular. Joel Pettit, our Executive Vice President – Operations and Marketing, worked in EOG’sMid-Continent Division for over a decade. Greg Condray, our Executive Vice President – Geosciences and Business Development, worked with Mr. Pettit in EOG’sMid-Continent Division as Division Exploration Manager, and had considerable experience at Chesapeake Energy leading initial delineation and development efforts in the Eagle Ford, Haynesville and Powder River Basin. We believe their experience is instrumental in the execution of our pursuit of operational and capital efficiencies.

Significant financial strength and flexibility. We believe we have a strong financial position, including a low debt profile and a large production base that generates significant cash flow, allowing us to strategically allocate capital in order to enhance shareholder value. We are well-positioned to adjust our development program based on market and industry conditions, as we have minimal commitments to deliver specified volumes, no rig contracts extending beyond 12 months and approximately 84% of our acreage is held by production as of December 31, 2018. We believe that our conservative capital structure, which we will seek to maintain through a disciplined approach to capital spending, and other potential financing sources will provide us with sufficient liquidity and flexibility to execute our development capital program.

Historical Capital Expenditures and Capital Budget

Our 2019 capital budget is approximately $515 million to $555 million. For the year ended December 31, 2018 and the three months ended March 31, 2019, our aggregate drilling and completion capital expenditures were approximately $705.2 million and $161.6 million, respectively.

Because we are the operator of a high percentage of our acreage and a majority of our acreage is held by production, the amount and timing of our capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, and prevailing and anticipated prices for oil and natural gas. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows and loss of acreage through lease expirations. In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

Our Properties

The map below depicts the location of our properties as of December 31, 2018.

LOGO

We refer to gross and net acreage where we are designated as operator or expect to be designated as operator based on the size of our working interest relative to other working interest owners as “our operated acreage” or acreage we “operated” in this prospectus. As of December 31, 2018, we operated approximately 71% of our net

acreage and had an average working interest of approximately 70% in all of our operated acreage. From January 1, 2018 through December 31, 2018, we drilled or participated in 214 gross horizontal wells on production.

As of December 31, 2018, approximately 84% of our total net acreage was held by production. This positions us to control the pace of our development efforts, strategically develop our acreage with a near-term focus onhigh-return projects, limit expenditures on lease renewals and limit the risk of losing high quality acreage through expiration of leases. Additionally, we closely monitor activity of other industry participants and adjust our future development plans based on information and what we believe to be best practices learned from our peers.

For the three months ended March 31, 2019, our average net daily production was 48.9 MBoe/d (approximately 26% oil, 44% natural gas and 30% NGLs). During 2018, our average net daily production was 43.7 MBoe/d (approximately 27% oil, 44% natural gas and 29% NGLs). As of December 31, 2018, we had 1,263 gross (501 net) producing wells online, operated andnon-operated.

Oil and Natural Gas Data

Proved Reserves

Evaluation of Proved Reserves. Approximately 93% of our proved reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers. Our personnel prepared reserve estimates with respect to the remaining approximate 7% of our proved reserves as of December 31, 2018.

DeGolyer and MacNaughton is a petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. Within DeGolyer and MacNaughton, the technical person primarily responsible for preparing our reserves estimates was Gregory K. Graves, P.E. Mr. Graves is a Registered Professional Engineer in the State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers (“SPE”) and the Society of Petroleum Evaluation Engineers and has in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum Engineering.

Mr. Graves meets the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

DeGolyer and MacNaughton does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of DeGolyer and MacNaughton’s proved reserve report as of December 31, 2018 is included as an exhibit to the registration statement of which this prospectus forms a part.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with our independent reserve engineers periodically to review properties and to discuss the assumptions and methods used in the proved reserve estimation process. Our Corporate Reserves Advisor is primarily responsible for overseeing the preparation of the reserves estimates by DeGolyer and MacNaughton. Our Corporate Reserves Advisor holds a Bachelor of Science in petroleum engineering technology, has over 25 years of industry experience and over 10 years of experience in corporate reserves preparation.

The preparation of our proved reserve estimates was completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

review and verification of historical production data, which data is based on actual reported production;

preparation of majority of our reserve estimates by third-party engineering firm;

review for compliance with the SEC and GAAP standards;

review by our management team of reported proved reserves and significant reserve changes; and

verification of property ownership by our land department.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2018 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy.Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developednon-producing (“PDNP”) and PUD reserves for our properties, due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion

information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Reserves. The following table presents summary data with respect to our estimated net proved reserves as of December 31, 2018. The reserve estimates attributable to our properties as of December 31, 2018 were prepared in accordance with the rules and regulations of the SEC regarding reserve reporting.

   As of December 31, 2018(1) 

Proved developed reserves:

  

Oil (MBbls)

   18,652 

Natural gas (MMcf)

   369,677 

NGLs (MBbls)

   39,927 
  

 

 

 

Total (MBoe)(2)

   120,192 

Proved undeveloped reserves:

  

Oil (MBbls)

   37,031 

Natural gas (MMcf)

   541,505 

NGLs (MBbls)

   58,485 
  

 

 

 

Total (MBoe)(2)

   185,767 

Total proved reserves:

  

Oil (MBbls)

   55,683 

Natural gas (MMcf)

   911,182 

NGLs (MBbls)

   98,412 
  

 

 

 

Total (MBoe)(2)

   305,959 
  

 

 

 

Benchmark Oil and Natural Gas Prices(1):

  

Oil—WTI per Bbl

  $65.66 

Natural gas—Henry Hub per MMBtu

  $3.16 

Standardized measure (in thousands)(3)

  $1,699,701 

PV-10 of proved reserves (in thousands)(4)

  $2,091,509 

(1)

Our estimated net proved reserves were determined using averagefirst-day-of-the-month prices for the prior 12 months in accordance with SEC guidance adjusted for quality, transportation fees, regional price differentials, and in the case of natural gas, energy content. For oil and NGLs volumes, the average WTI posted price of $65.66 per barrel as of December 31, 2018, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $3.16 per MMBtu as of December 31, 2018 was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.49 per barrel of oil, $20.35 per barrel of NGLs and $1.90 per Mcf of natural gas as of December 31, 2018.

(2)

Totals may not sum or recalculate due to rounding.

(3)

Please see “Risk Factors— The standardized measure of our estimated reserves contained in this prospectus and in the footnotes to our financial statements is not an accurate estimate of the current fair value of our estimated reserves.”

(4)

PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. NeitherPV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry usePV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Please see “Summary Historical and Unaudited Pro Forma FinancialData—Non-GAAP FinancialMeasure—PV-10.”

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please see “Risk Factors” appearing elsewhere in this prospectus.

Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this prospectus and in the reserve report of DeGolyer and MacNaughton as of December 31, 2018, which is included as an exhibit to the registration statement of which this prospectus forms a part.

PUDs

As of December 31, 2018, our PUDs totaled 37,031 MBbls of oil, 541,505 MMcf of natural gas and 58,485 MBbls of NGLs, for a total of 185,767 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells are drilled and begin production.

The following table summarizes our changes in PUDs during the year ended December 31, 2018 (in MBoe):

Balance, December 31, 2017

151,724

Extensions and discoveries

127,804

Revisions of previous estimates

(67,260

Transfers to proved developed

(26,501

Balance, December 31, 2018

185,767 
  

 

 

 

Leasehold interests—net acres (in thousands)

1,116

��

Extensions and discoveries of 127,804 MBoe during the year ended December 31, 2018 resulted primarily from proved undeveloped locations added as a result of the continued development of our acreage and the drilling activity of other operators in the area. Downward revisions of previous estimates of 67,260 MBoe during the year ended December 31, 2018 were primarily due to adjustments to unit spacing, wellbore lateral length and other factors as we refined our current development plan. During the year ended December 31, 2018, we spent $119.8 million to convert 26,501 MBoe to proved developed producing reserves.

Our estimated future development costs relating to the development of PUDs at December 31, 2018 were projected to be approximately $1.2 billion over the next five years, which we expect to finance through cash flow from operations, borrowings under our credit facility and other sources of capital. All of our proved undeveloped reserves are expected to be developed within five years of initial booking. Please see “Risk Factors—Risks Related to Our Business—The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.”

As of December 31, 2018, approximately 21,930 MBoe of our total proved reserves relating to 33 drilled but uncompleted wells (“DUCs”) were classified as PUDs, which is reflected in proved undeveloped reserves above. These DUCs are all scheduled to be completed within the next six months and have remaining completion costs of approximately $98.7 million.

Oil and Natural Gas Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

   Three Months Ended
March 31,
   Year Ended December 31, 
   2019   2018   2018   2017   2016 

Production data:

          

Oil (MBbls)

   1,139    1,038    4,364    1,454    739 

Natural gas (MMcf)

   11,620    8,912    41,890    17,582    6,382 

NGLs (MBbls)

   1,329    874    4,592    1,524    546 

Total (MBoe)(1)

   4,405    3,397    15,938    5,908    2,349 

Average daily production (MBoe/d)

   48.9    37.7    43.7    16.2    6.4 

Average prices(2):

          

Oil (per Bbl)

  $53.18   $  61.36   $63.07   $52.87   $41.36 

Natural gas (per Mcf)

  $1.87   $1.90   $1.82   $2.80   $2.52 

NGLs (per Bbl)

  $12.18   $23.33   $19.27   $26.44   $15.21 

Total (per Boe)

  $22.37   $29.72   $27.59   $28.16   $23.40 

Average realized prices after effects of derivative settlements(2):

          

Oil (per Bbl)

  $59.46   $56.78   $55.87   $53.57   $41.36 

Natural gas (per Mcf)

  $1.53   $1.92   $1.73   $2.89   $2.52 

NGLs (per Bbl)

  $13.86   $23.33   $19.60   $26.44   $15.21 

Total (per Boe)

  $23.59   $28.39   $25.48   $28.60   $23.40 

Average costs (per MBoe)(2):

          

Production expenses

  $3.37   $2.46   $2.99   $2.86   $2.17 

Gathering, transportation and processing expenses

   —      —     $—     $3.15   $2.52 

Production taxes

  $1.14   $0.70   $1.10   $0.62   $0.46 

General and administrative(3)

  $3.59   $4.13   $3.82   $5.31   $2.38 

 

(1)Does

May not include optimization projects.sum or recalculate due to rounding.

(2)

Average prices and costs for the three months ended March 31, 2019 and 2018 and the year ended December 31, 2018 reflect the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

(3)

General and administrative expenses for the three months ended March 31, 2019 and 2018 and the year ended December 31, 2018 and 2017 include $0.70 per Boe, $0.67 per Boe, $0.69 per Boe and $0.06 per Boe, respectively, of equity-based compensation expense.

Index to Financial Statements

As shown in the table above, as of December 31, 2011, LINN had 2,302 proved undeveloped drilling locations (specific drilling locations as to which the independent engineering firm DeGolyer and MacNaughton assigned proved undeveloped reserves as of such date) and LINN had identified 4,154 additional unproved drilling locations (specific drilling locations as to which DeGolyer and MacNaughton has not assigned any proved reserves) on acreage that LINN has under existing leases. As successful development wells frequently result in the reclassification of adjacent lease acreage from unproved to proved, LINN expects that a significant number of its unproved drilling locations will be reclassified as proved drilling locations prior to the actual drilling of these locations.

Productive WellsProved Reserves

The following sets forth information relating to the productive wells in which LINN owned a working interestEvaluation of Proved Reserves. Approximately 93% of our proved reserve estimates as of December 31, 2011. Productive wells consist2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers. Our personnel prepared reserve estimates with respect to the remaining approximate 7% of our proved reserves as of December 31, 2018.

DeGolyer and MacNaughton is a petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. Within DeGolyer and MacNaughton, the technical person primarily responsible for preparing our reserves estimates was Gregory K. Graves, P.E. Mr. Graves is a Registered Professional Engineer in the State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers (“SPE”) and the Society of Petroleum Evaluation Engineers and has in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum Engineering.

Mr. Graves meets the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

DeGolyer and MacNaughton does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of DeGolyer and MacNaughton’s proved reserve report as of December 31, 2018 is included as an exhibit to the registration statement of which this prospectus forms a part.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with our independent reserve engineers periodically to review properties and to discuss the assumptions and methods used in the proved reserve estimation process. Our Corporate Reserves Advisor is primarily responsible for overseeing the preparation of the reserves estimates by DeGolyer and MacNaughton. Our Corporate Reserves Advisor holds a Bachelor of Science in petroleum engineering technology, has over 25 years of industry experience and over 10 years of experience in corporate reserves preparation.

The preparation of our proved reserve estimates was completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

review and verification of historical production data, which data is based on actual reported production;

preparation of majority of our reserve estimates by third-party engineering firm;

review for compliance with the SEC and GAAP standards;

review by our management team of reported proved reserves and significant reserve changes; and

verification of property ownership by our land department.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2018 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells and wells capablewere estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production including wells awaiting pipeline or other connectionsperformance and analogy to commence deliveries. “Gross” wells referssimilar production, both of which are considered to provide a reasonably high degree of accuracy.Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developednon-producing (“PDNP”) and PUD reserves for our properties, due to the total numberabundance of producing wellsanalog data.

To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in which LINN hasthe same reservoir or an interest,analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and “net” wells refershave been demonstrated to provide reasonably certain results with consistency and repeatability in the sumformation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of its fractional working interests ownedour proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion

information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Reserves. The following table presents summary data with respect to our estimated net proved reserves as of December 31, 2018. The reserve estimates attributable to our properties as of December 31, 2018 were prepared in gross wells. The numberaccordance with the rules and regulations of wells below does not include approximately 2,500 productive wells in which LINN owns a royalty interest only.the SEC regarding reserve reporting.

 

       Natural Gas Wells       Oil Wells   Total Wells 
   Gross   Net   Gross   Net   Gross   Net 

Operated(1)

   3,889     2,925     3,870     3,578     7,759     6,503  

Nonoperated(2)

   1,843     369     1,628     207     3,471     576  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   5,732     3,294     5,498     3,785     11,230     7,079  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   As of December 31, 2018(1) 

Proved developed reserves:

  

Oil (MBbls)

   18,652 

Natural gas (MMcf)

   369,677 

NGLs (MBbls)

   39,927 
  

 

 

 

Total (MBoe)(2)

   120,192 

Proved undeveloped reserves:

  

Oil (MBbls)

   37,031 

Natural gas (MMcf)

   541,505 

NGLs (MBbls)

   58,485 
  

 

 

 

Total (MBoe)(2)

   185,767 

Total proved reserves:

  

Oil (MBbls)

   55,683 

Natural gas (MMcf)

   911,182 

NGLs (MBbls)

   98,412 
  

 

 

 

Total (MBoe)(2)

   305,959 
  

 

 

 

Benchmark Oil and Natural Gas Prices(1):

  

Oil—WTI per Bbl

  $65.66 

Natural gas—Henry Hub per MMBtu

  $3.16 

Standardized measure (in thousands)(3)

  $1,699,701 

PV-10 of proved reserves (in thousands)(4)

  $2,091,509 

 

(1)LINN had

Our estimated net proved reserves were determined using averagefirst-day-of-the-month prices for the prior 12 operated wellsmonths in accordance with multiple completions atSEC guidance adjusted for quality, transportation fees, regional price differentials, and in the case of natural gas, energy content. For oil and NGLs volumes, the average WTI posted price of $65.66 per barrel as of December 31, 2011.2018, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $3.16 per MMBtu as of December 31, 2018 was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.49 per barrel of oil, $20.35 per barrel of NGLs and $1.90 per Mcf of natural gas as of December 31, 2018.

(2)LINN had no nonoperated wells

Totals may not sum or recalculate due to rounding.

(3)

Please see “Risk Factors— The standardized measure of our estimated reserves contained in this prospectus and in the footnotes to our financial statements is not an accurate estimate of the current fair value of our estimated reserves.”

(4)

PV-10 is not a financial measure calculated or presented in accordance with multiple completions at December 31, 2011.GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. NeitherPV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry usePV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Please see “Summary Historical and Unaudited Pro Forma FinancialData—Non-GAAP FinancialMeasure—PV-10.”

Developed

Reserve engineering is and Undeveloped Acreagemust be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please see “Risk Factors” appearing elsewhere in this prospectus.

The following sets forthAdditional information relatingregarding our proved reserves can be found in the notes to leasehold acreageour financial statements included elsewhere in this prospectus and in the reserve report of DeGolyer and MacNaughton as of December 31, 2011:

   Developed
Acreage
   Undeveloped
Acreage
   Total
Acreage
 
   Gross   Net   Gross   Net   Gross   Net 
   (in thousands) 

Leasehold acreage

   2,352     1,060     133     56     2,485     1,116  

Production, Price and Cost History

LINN’s natural gas production2018, which is primarily sold under market sensitive price contracts, which typically sell at a differentialincluded as an exhibit to the New York Mercantile Exchange (“NYMEX”), Panhandle Eastern Pipeline (“PEPL”), El Paso Permian Basin, or MichCon city-gate natural gas prices due to the Btu content and the proximity to major consuming markets. LINN’s natural gas production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. By the termsregistration statement of the percentage-of-proceeds contracts, LINN receiveswhich this prospectus forms a percentagepart.

PUDs

As of the resale price received by the purchaser for salesDecember 31, 2018, our PUDs totaled 37,031 MBbls of residualoil, 541,505 MMcf of natural gas and NGL recovered after transportation58,485 MBbls of NGLs, for a total of 185,767 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells are drilled and processing of natural gas. These purchasers sell the residual natural gas and NGL based primarily on spot market prices. Under percentage-of-index contracts, the price per MMBtu LINN receives for natural gas is tied to indexes publishedbegin production.

The following table summarizes our changes inGas DailyorInside FERC Gas Market Report.Although exact percentages vary daily, as of December 31, 2011, approximately 90% of LINN’s natural gas and NGL production was sold under short-term contracts at market-sensitive or spot prices. At December 31, 2011, LINN had natural gas throughput delivery commitments under long-term contracts of approximately 784 MMcf for PUDs during the year ended December 31, 2012,2018 (in MBoe):

Balance, December 31, 2017

151,724

Extensions and discoveries

127,804

Revisions of previous estimates

(67,260

Transfers to proved developed

(26,501

Balance, December 31, 2018

185,767

Extensions and approximatelydiscoveries of 127,804 MBoe during the year ended December 31, Bcf2018 resulted primarily from proved undeveloped locations added as a result of the continued development of our acreage and the drilling activity of other operators in the area. Downward revisions of previous estimates of 67,260 MBoe during the year ended December 31, 2018 were primarily due to adjustments to unit spacing, wellbore lateral length and other factors as we refined our current development plan. During the year ended December 31, 2018, we spent $119.8 million to convert 26,501 MBoe to proved developed producing reserves.

Our estimated future development costs relating to the development of PUDs at December 31, 2018 were projected to be delivered by August 2015.

approximately $1.2 billion over the next five years, which we expect to finance through cash flow from operations, borrowings under our credit facility and other sources of capital. All of our proved undeveloped reserves are expected to be developed within five years of initial booking. Please see “Risk Factors—Risks Related to Our Business—The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.”

Index to Financial Statements

LINN’s oil production is primarily sold under market sensitive contracts, which typically sell at a differential to NYMEX, and asAs of December 31, 2011,2018, approximately 90%21,930 MBoe of its oil production was sold under short-term contracts. At December 31, 2011, LINN had no delivery commitments for oil production.our total proved reserves relating to 33 drilled but uncompleted wells (“DUCs”) were classified as PUDs, which is reflected in proved undeveloped reserves above. These DUCs are all scheduled to be completed within the next six months and have remaining completion costs of approximately $98.7 million.

As discussed in the “Strategy” section above, LINN enters into derivative contracts primarily in the form of swap contracts

Oil and put options to reduce the impact of commodity price volatility on its cash flow from operations. By removing a significant portion of the price volatility associated with future production, LINN expects to mitigate, but not eliminate, the potential effects of variability in cash flow due to fluctuations in commodity prices.Natural Gas Production Prices and Costs

Production and Price History

The following table sets forth information regarding average dailynet production average pricesof oil, natural gas and average costsNGLs, and certain price and cost information for each of the periods indicated:

 

   Year Ended December 31,   Three Months Ended
March 31,
 
   2009   2010   2011   2011   2012 

Average daily production:

          

Natural gas (MMcf/d)

   125     137     175     158     229  

Oil (MBbls/d)

   9.0     13.1     21.5     17.2     26.1  

NGL (MBbls/d)

   6.5     8.3     10.8     8.6     14.2  

Total (MMcfe/d)

   218     265     369     312     471  

Weighted average prices (hedged):(1)

          

Natural gas (Mcf)

  $8.27    $8.52    $8.20    $8.99    $6.33  

Oil (Bbl)

  $110.94    $94.71    $89.21    $86.24    $92.80  

NGL (Bbl)

  $28.04    $39.14    $42.88    $45.81    $40.21  

Weighted average prices (unhedged):(2)

          

Natural gas (Mcf)

  $3.51    $4.24    $4.35    $4.71    $3.16  

Oil (Bbl)

  $55.25    $75.16    $91.24    $89.44    $97.25  

NGL (Bbl)

  $28.04    $39.14    $42.88    $45.81    $40.21  

Average NYMEX prices:

          

Natural gas (MMBtu)

  $3.99    $4.40    $4.05    $4.13    $2.74  

Oil (Bbl)

  $61.94    $79.53    $95.12    $94.10    $102.93  

Costs per Mcfe of production:

          

Lease operating expenses

  $1.67    $1.64    $1.73    $1.63    $1.67  

Transportation expenses

  $0.23    $0.20    $0.21    $0.21    $0.25  

General and administrative expenses(3)

  $1.08    $1.02    $0.99    $1.09    $1.01  

Depreciation, depletion and amortization

  $2.53    $2.46    $2.48    $2.36    $2.74  

Taxes, other than income taxes

  $0.35    $0.47    $0.58    $0.56    $0.59  
   Three Months Ended
March 31,
   Year Ended December 31, 
   2019   2018   2018   2017   2016 

Production data:

          

Oil (MBbls)

   1,139    1,038    4,364    1,454    739 

Natural gas (MMcf)

   11,620    8,912    41,890    17,582    6,382 

NGLs (MBbls)

   1,329    874    4,592    1,524    546 

Total (MBoe)(1)

   4,405    3,397    15,938    5,908    2,349 

Average daily production (MBoe/d)

   48.9    37.7    43.7    16.2    6.4 

Average prices(2):

          

Oil (per Bbl)

  $53.18   $  61.36   $63.07   $52.87   $41.36 

Natural gas (per Mcf)

  $1.87   $1.90   $1.82   $2.80   $2.52 

NGLs (per Bbl)

  $12.18   $23.33   $19.27   $26.44   $15.21 

Total (per Boe)

  $22.37   $29.72   $27.59   $28.16   $23.40 

Average realized prices after effects of derivative settlements(2):

          

Oil (per Bbl)

  $59.46   $56.78   $55.87   $53.57   $41.36 

Natural gas (per Mcf)

  $1.53   $1.92   $1.73   $2.89   $2.52 

NGLs (per Bbl)

  $13.86   $23.33   $19.60   $26.44   $15.21 

Total (per Boe)

  $23.59   $28.39   $25.48   $28.60   $23.40 

Average costs (per MBoe)(2):

          

Production expenses

  $3.37   $2.46   $2.99   $2.86   $2.17 

Gathering, transportation and processing expenses

   —      —     $—     $3.15   $2.52 

Production taxes

  $1.14   $0.70   $1.10   $0.62   $0.46 

General and administrative(3)

  $3.59   $4.13   $3.82   $5.31   $2.38 

 

(1)Includes the effect of realized gains on derivatives of approximately $401 million (excluding $49 million realized net gains on canceled contracts), $308 million, $230 million (excluding $27 million realized gains on canceled contracts), $56 million

May not sum or recalculate due to rounding.

(2)

Average prices and $55 millioncosts for the years ended December 31, 2009, December 31, 2010, and December 31, 2011, and the three months ended March 31, 20112019 and March2018 and the year ended December 31, 2012, respectively.

(2)Does2018 reflect the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not includebeen adjusted and continues to be reported under the effect of realized gains (losses) on derivatives.previous revenue standard.

(3)

General and administrative expenses for the years ended December 31, 2009, December 31, 2010, and December 31, 2011, and the three months ended March 31, 20112019 and March 31, 2012, include approximately $15 million, $13 million, $21 million, $5 million2018 and $8 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the yearsyear ended December 31, 2009, December 31, 2010,2018 and December 31, 2011,2017 include $0.70 per Boe, $0.67 per Boe, $0.69 per Boe and the three months ended March 31, 2011 and March 31, 2012, were $0.90$0.06 per Mcfe, $0.88 per Mcfe, $0.83 per Mcfe, $0.90 Mcfe and $0.83 Mcfe, respectively. This measure is not in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) and thus is a non-GAAP measure, used by management to analyze LINN’s performance.Boe, respectively, of equity-based compensation expense.

Index to Financial Statements

Reserve Data

Proved Reserves

Evaluation of Proved Reserves. Approximately 93% of our proved reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers. Our personnel prepared reserve estimates with respect to the remaining approximate 7% of our proved reserves as of December 31, 2018.

DeGolyer and MacNaughton is a petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. Within DeGolyer and MacNaughton, the technical person primarily responsible for preparing our reserves estimates was Gregory K. Graves, P.E. Mr. Graves is a Registered Professional Engineer in the State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers (“SPE”) and the Society of Petroleum Evaluation Engineers and has in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum Engineering.

Mr. Graves meets the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

DeGolyer and MacNaughton does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of DeGolyer and MacNaughton’s proved reserve report as of December 31, 2018 is included as an exhibit to the registration statement of which this prospectus forms a part.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with our independent reserve engineers periodically to review properties and to discuss the assumptions and methods used in the proved reserve estimation process. Our Corporate Reserves Advisor is primarily responsible for overseeing the preparation of the reserves estimates by DeGolyer and MacNaughton. Our Corporate Reserves Advisor holds a Bachelor of Science in petroleum engineering technology, has over 25 years of industry experience and over 10 years of experience in corporate reserves preparation.

The following sets forthpreparation of our proved reserve estimates was completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

review and verification of historical production data, which data is based on actual reported production;

preparation of majority of our reserve estimates by third-party engineering firm;

review for compliance with the SEC and GAAP standards;

review by our management team of reported proved reserves and significant reserve changes; and

verification of property ownership by our land department.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2018 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and NGLthe second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy.Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developednon-producing (“PDNP”) and PUD reserves for our properties, due to the abundance of analog data.

To estimate economically recoverable proved reserves and the standardized measure of discountedrelated future net cash flows, atwe considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion

information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Reserves. The following table presents summary data with respect to our estimated net proved reserves as of December 31, 2011, based on2018. The reserve reportsestimates attributable to our properties as of December 31, 2018 were prepared by independent engineers, DeGolyerin accordance with the rules and MacNaughton:regulations of the SEC regarding reserve reporting.

 

Estimated proved developed reserves:

  

Natural gas (Bcf)

   998  

Oil (MMBbls)

   125  

NGL (MMBbls)

   48  

Total (Bcfe)

   2,034  

Estimated proved undeveloped reserves:

  

Natural gas (Bcf)

   677  

Oil (MMBbls)

   64  

NGL (MMBbls)

   46  

Total (Bcfe)

   1,336  

Estimated total proved reserves (Bcfe)

   3,370  

Proved developed reserves as a percentage of total proved reserves

   60

Standardized measure of discounted future net cash flows (in millions)(1)

  $6,615  

Representative NYMEX prices:(2)

  

Natural gas (MMBtu)

  $4.12  

Oil (Bbl)

  $95.84  
   As of December 31, 2018(1) 

Proved developed reserves:

  

Oil (MBbls)

   18,652 

Natural gas (MMcf)

   369,677 

NGLs (MBbls)

   39,927 
  

 

 

 

Total (MBoe)(2)

   120,192 

Proved undeveloped reserves:

  

Oil (MBbls)

   37,031 

Natural gas (MMcf)

   541,505 

NGLs (MBbls)

   58,485 
  

 

 

 

Total (MBoe)(2)

   185,767 

Total proved reserves:

  

Oil (MBbls)

   55,683 

Natural gas (MMcf)

   911,182 

NGLs (MBbls)

   98,412 
  

 

 

 

Total (MBoe)(2)

   305,959 
  

 

 

 

Benchmark Oil and Natural Gas Prices(1):

  

Oil—WTI per Bbl

  $65.66 

Natural gas—Henry Hub per MMBtu

  $3.16 

Standardized measure (in thousands)(3)

  $1,699,701 

PV-10 of proved reserves (in thousands)(4)

  $2,091,509 

 

(1)This measure is not intended to represent

Our estimated net proved reserves were determined using averagefirst-day-of-the-month prices for the market valueprior 12 months in accordance with SEC guidance adjusted for quality, transportation fees, regional price differentials, and in the case of estimated reserves.natural gas, energy content. For oil and NGLs volumes, the average WTI posted price of $65.66 per barrel as of December 31, 2018, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $3.16 per MMBtu as of December 31, 2018 was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.49 per barrel of oil, $20.35 per barrel of NGLs and $1.90 per Mcf of natural gas as of December 31, 2018.

(2)In

Totals may not sum or recalculate due to rounding.

(3)

Please see “Risk Factors— The standardized measure of our estimated reserves contained in this prospectus and in the footnotes to our financial statements is not an accurate estimate of the current fair value of our estimated reserves.”

(4)

PV-10 is not a financial measure calculated or presented in accordance with SEC regulations, reserves were estimated usingGAAP and generally differs from standardized measure, the average price duringmost directly comparable GAAP financial measure, because it does not include the 12-month period, determined aseffects of income taxes on future net revenues. NeitherPV-10 nor standardized measure represents an unweighted averageestimate of the first-day-of-the-month price for each month, unless prices are definedfair market value of our oil and natural gas properties. We and others in the industry usePV-10 as a measure to compare the relative size and value of proved reserves held by contractual arrangements, excluding escalations based upon future conditions. The average price usedcompanies without regard to estimate reserves is held constant over the lifespecific tax characteristics of the reserves.such entities. Please see “Summary Historical and Unaudited Pro Forma FinancialData—Non-GAAP FinancialMeasure—PV-10.”

During the year ended December 31, 2011, LINN’s proved undeveloped reserves (“PUDs”) increased to 1,336 Bcfe from 935 Bcfe at December 31, 2010, representing an increase of 401 Bcfe. The increase was primarily due to 364 Bcfe added as a result of LINN’s acquisitions in the Mid-Continent Deep, Permian Basin and Williston Basin regions and 346 Bcfe added as a result of its drilling activities in the Texas Panhandle Granite Wash, partially offset by PUDs developed during 2011.

During the year ended December 31, 2011, LINN incurred approximately $307 million in capital expenditures to convert 178 Bcfe of reserves classified as PUDs at December 31, 2010. Based on the December 31, 2011 reserve report, the amounts of capital expenditures estimated to be incurred in 2012, 2013 and 2014 to develop LINN’s PUDs are approximately $765 million, $836 million and $556 million, respectively. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and product prices. Of the 1,336 Bcfe of PUDs at December 31, 2011, seven Bcfe remained undeveloped for five years or more; however, the property is included in LINN’s 2012 development plan. All PUD properties are included in LINN’s current five-year development plan.

Reserve engineering is inherentlyand must be recognized as a subjective process of estimating underground accumulationsvolumes of economically recoverable oil and natural gas and NGL that cannot be measured exactly.in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretationinterpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and judgment.production may justify revisions of such estimates. Accordingly, reserve estimates may varyoften differ from the quantities of oil, natural gas and NGL that are ultimately recovered. Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows. The standardized measure of discounted future net

Index to Financial Statements

cash flows should not be construed as the market value of the reserves at the dates shown. The 10% discount factor required to be used under the provisions of applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with LINN or the oil and natural gas industry. The standardized measure of discounted future net cash flows is materially affected by assumptions about the timing of future production, which may prove to be inaccurate.

The reserve estimates reported herein were prepared by independent engineers, DeGolyer and MacNaughton. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, is based in part on data provided by LINN. When preparing the reserve estimates, the independent engineering firm did not independently verify the accuracy and completeness of the information and data furnished by LINN with respect to ownership interests, production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention that brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years. The independent engineering firm also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

LINN’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of LINN’s reserve estimates in accordance with SEC regulations. The preparation of reserve estimates was overseen by LINN’s Reservoir Engineering Advisor, who has Master of Petroleum Engineering and Master of Business Administration degrees and more than 25 years of oil and natural gas industry experience. The reserve estimates were reviewed and approved by LINN’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer. LINN has not filed reserve estimates with any federal authority or agency, with the exception of the SEC.

Operational Overview

General

LINN generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects that not only replace production, but add value through reserve and production growth and future operational synergies. Many of LINN’s wells are completed in multiple producing zones with commingled production and long economic lives.

Principal Customers

For the year ended December 31, 2011, sales of oil, natural gas and NGL to Enbridge Energy Partners, L.P. and DCP Midstream Partners, LP accounted for approximately 21% and 19%, respectively, of LINN’s total production volumes, or 40% in the aggregate. If LINN were to lose any one of its major oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of its oil and natural gas in that particular purchaser’s service area. If LINN were to lose a purchaser, it believes it could identify a substitute purchaser. However, if one or more of these large purchasers ceased purchasing oil and natural gas altogether, it could have a detrimental effect on the oil and natural gas market in general and on the volume of oil and natural gas that LINNare ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please see “Risk Factors” appearing elsewhere in this prospectus.

Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this prospectus and in the reserve report of DeGolyer and MacNaughton as of December 31, 2018, which is ableincluded as an exhibit to sell.the registration statement of which this prospectus forms a part.

PUDs

As of December 31, 2018, our PUDs totaled 37,031 MBbls of oil, 541,505 MMcf of natural gas and 58,485 MBbls of NGLs, for a total of 185,767 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells are drilled and begin production.

The following table summarizes our changes in PUDs during the year ended December 31, 2018 (in MBoe):

Balance, December 31, 2017

151,724

Extensions and discoveries

127,804

Revisions of previous estimates

(67,260

Transfers to proved developed

(26,501

Balance, December 31, 2018

185,767

Extensions and discoveries of 127,804 MBoe during the year ended December 31, 2018 resulted primarily from proved undeveloped locations added as a result of the continued development of our acreage and the drilling activity of other operators in the area. Downward revisions of previous estimates of 67,260 MBoe during the year ended December 31, 2018 were primarily due to adjustments to unit spacing, wellbore lateral length and other factors as we refined our current development plan. During the year ended December 31, 2018, we spent $119.8 million to convert 26,501 MBoe to proved developed producing reserves.

Our estimated future development costs relating to the development of PUDs at December 31, 2018 were projected to be approximately $1.2 billion over the next five years, which we expect to finance through cash flow from operations, borrowings under our credit facility and other sources of capital. All of our proved undeveloped reserves are expected to be developed within five years of initial booking. Please see “Risk Factors—Risks Related to Our Business—The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.”

As of December 31, 2018, approximately 21,930 MBoe of our total proved reserves relating to 33 drilled but uncompleted wells (“DUCs”) were classified as PUDs, which is reflected in proved undeveloped reserves above. These DUCs are all scheduled to be completed within the next six months and have remaining completion costs of approximately $98.7 million.

Oil and Natural Gas Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

   Three Months Ended
March 31,
   Year Ended December 31, 
   2019   2018   2018   2017   2016 

Production data:

          

Oil (MBbls)

   1,139    1,038    4,364    1,454    739 

Natural gas (MMcf)

   11,620    8,912    41,890    17,582    6,382 

NGLs (MBbls)

   1,329    874    4,592    1,524    546 

Total (MBoe)(1)

   4,405    3,397    15,938    5,908    2,349 

Average daily production (MBoe/d)

   48.9    37.7    43.7    16.2    6.4 

Average prices(2):

          

Oil (per Bbl)

  $53.18   $  61.36   $63.07   $52.87   $41.36 

Natural gas (per Mcf)

  $1.87   $1.90   $1.82   $2.80   $2.52 

NGLs (per Bbl)

  $12.18   $23.33   $19.27   $26.44   $15.21 

Total (per Boe)

  $22.37   $29.72   $27.59   $28.16   $23.40 

Average realized prices after effects of derivative settlements(2):

          

Oil (per Bbl)

  $59.46   $56.78   $55.87   $53.57   $41.36 

Natural gas (per Mcf)

  $1.53   $1.92   $1.73   $2.89   $2.52 

NGLs (per Bbl)

  $13.86   $23.33   $19.60   $26.44   $15.21 

Total (per Boe)

  $23.59   $28.39   $25.48   $28.60   $23.40 

Average costs (per MBoe)(2):

          

Production expenses

  $3.37   $2.46   $2.99   $2.86   $2.17 

Gathering, transportation and processing expenses

   —      —     $—     $3.15   $2.52 

Production taxes

  $1.14   $0.70   $1.10   $0.62   $0.46 

General and administrative(3)

  $3.59   $4.13   $3.82   $5.31   $2.38 

(1)

May not sum or recalculate due to rounding.

(2)

Average prices and costs for the three months ended March 31, 2019 and 2018 and the year ended December 31, 2018 reflect the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

(3)

General and administrative expenses for the three months ended March 31, 2019 and 2018 and the year ended December 31, 2018 and 2017 include $0.70 per Boe, $0.67 per Boe, $0.69 per Boe and $0.06 per Boe, respectively, of equity-based compensation expense.

Productive Wells

The following table sets forth information as of December 31, 2018 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated andnon-operated, and net wells are the sum of our fractional working interests owned in gross wells.

   Oil   Natural Gas   Total 
   Gross   Net   Gross   Net   Gross   Net 

Total:

            

Operated

   140    110    451    339    591    449 

Non-operated

   318    19    354    34    672    53 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   458    129    805    373    1,263    502 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2018, relating to our leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

Developed Acreage  Undeveloped Acreage  Total Acreage 

Gross(1)

 Net(2)  Gross(1)  Net(2)  Gross(1)   Net(2) 
298,019  144,932   85,411   27,038   383,430    171,970 

(1)

A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(2)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. As of December 31, 2018, approximately 84% of our total net acreage was held by production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2018, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

2019

  2020  2021  2022  2023 and Thereafter

Gross

  Net  Gross  Net  Gross  Net  Gross  Net  Gross  Net

19,563

  6,675  42,712  10,766  10,944  4,056  —    —    —    —  

We intend to extend substantially all of the net acreage associated with our inventory of drilling locations through a combination of development drilling and leasehold extension and renewal payments. Of the 6,675 net acres expiring in 2019 and the 10,766 net acres expiring in 2020, we have the right to extend on 1,017 and 1,750 net acres, respectively.

Drilling Results

The following table sets forth the results of our drilling activity, as defined by wells having been placed on production, for the periods indicated. The information should not be considered indicative of future performance,

nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

   For the Year Ended December 31, 
   2018   2017   2016 
   Gross   Net   Gross   Net   Gross   Net 

Exploratory Wells:

            

Productive(1)

   —      —      —      —      —      —   

Dry

   —      —      —      —      —      —   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Exploratory

   —      —      —      —      —      —   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Development Wells:

            

Productive(1)

   214    72    93    35    55    19 

Dry

   —      —      —      —      —      —   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Development

   214    72    93    35    55    19 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Wells:

            

Productive(1)

   214    72    93    35    55    19 

Dry

   —      —      —      —      —      —   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   214    72    93    35    55    19 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1)

Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.

As of December 31, 2018, we had 33 gross (24 net) wells waiting on completion with associated remaining net completion costs of approximately $98.7 million.

Operations

General

As of December 31, 2018, we operated approximately 71% of our net acreage position. As operator, we design and manage the development of a well and supervise operation and maintenance activities on aday-to-day basis. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

We market the majority of our production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our oil, natural gas and NGL production to purchasers at market prices, adjusted for quality, transportation fees, regional price differentials, and in the case of natural gas, energy content. While a majority of our natural gas and NGLs is sold under long-term contracts with terms of greater than twelve months, a portion is sold undersix-month andmonth-to-month contracts. We sell all of our oil under contracts with terms of twelve months or less.

We normally sell our production to a relatively small number of customers, as is customary in our business. The following table identifies customers from whom we derived 10% or more of receipts from the sale of oil, natural gas and NGLs during the years ended December 31, 2018, 2017 and 2016:

   Year Ended December 31, 
   2018  2017  2016 

Coffeyville Resources Refining & Marketing LLC

   31  *   * 

Sunoco Inc.

   18  40  55

Blue Mountain Midstream, LLC(1)

   15  *   * 

EnLink Oklahoma Gas Processing, LP

   13  39  31

*

Revenue from customer was less than 10% in this period.

(1)

Certain of our directors are directors of Riviera Resources, Inc., which owns Blue Mountain Midstream, LLC. Please see “Certain Relationships and Related Party Transactions—Historical Transactions with Affiliates—Riviera Resources, Inc.”

During such periods, no other purchaser accounted for 10% or more of our revenue. We believe that the loss of any of these purchasers would not result in a material adverse effect on our financial condition or results of operations, as oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.

Transportation

During the initial development of our fields, we consider all gathering and delivery infrastructure options in the areas of our production which does not have an existing dedication. Our oil is transported from the wellsite tank batteries by truck to terminal pipeline sites or direct to a refinery. Our natural gas is generally transported by third-party gathering lines from the wellhead to a gas processing facility.

Volume Commitment

The substantial majority of our midstream agreements are structured as acreage dedications with no specified volume commitments. However, we do have one agreement with a third party that requires us to deliver a minimum volume of natural gas from a specified dedication area. In the event that we are unable to meet this natural gas volume delivery commitment, we would incur deficiency fees on any undelivered volumes as of November 2021. If we were unable to deliver any additional natural gas volumes subsequent to March 31, 2019 through November 2021, we would owe deficiency fees of $7.5 million at the end of the commitment period.

Competition

The oil and natural gas industry is highly competitive. LINN encounters strong competition fromintensely competitive, and we compete with other independent operatorscompanies, many of whom have greater resources than we do. Many of these companies not only explore for and master limited partnerships in acquiring properties, contracting for drilling and other

Index to Financial Statements

related services and securing trained personnel. LINN is also affected by competition for drilling rigs and the availability of related equipment. In the past, theproduce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of complying with existing, and subsequently amended, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate

transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, has experienced shortageswe may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of drilling rigs, equipment, pipeenergy legislation and/or regulation considered from time to time by the governments of the United States and personnel,the jurisdictions in which has delayed development drilling and has caused significant price increases. LINNwe operate. It is unablenot possible to predict when,the nature of any such legislation or if, such shortagesregulation which may occurultimately be adopted or how theyits effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of complying with existing, and subsequently amended, federal, state and local laws and regulations more easily than we can, which would adversely affect its drilling program.our competitive position.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Operating Hazards and Insurance

The oil and natural gas industry involves a variety of operating hazards and risks that could result in substantial losses from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, and suspension of operations. LINNThe Company may be liable for environmental damages caused by previous owners of property it purchases and leases. As a result, LINNthe Company may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds otherwise available, for acquisitions, development or distributions, or result in the loss of properties. In addition, LINNthe Company participates in wells on a nonoperated basis and therefore may be limited in its ability to control the risks associated with the operation of such wells.

In accordance with customary industry practices, LINNthe Company maintains insurance against some, but not all, potential losses. LINNThe Company cannot provide assurance that any insurance it obtains will be adequate to cover any losses or liabilities. LINNThe Company has elected to self-insure for certain items for which it has determined that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on LINN’sthe Company’s financial position, and results of operations.operations and cash flows. For more information about potential risks that could affect LINN,the Company, please readsee “Risk Factors.”

Title to Properties

PriorAs is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to the commencementour properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations LINN conductson those properties, we conduct a thorough title examination and performsperform curative work with respect to significant defects.defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, LINN iswe are typically responsible for curing any title defects at its expense priorour expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have in our possession or have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to commencing drilling operations. our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas leases, LINN performswe perform title reviews on the most significant leases and, depending on the materiality of properties, LINNwe may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. As a result, LINN has obtained title opinions on a significant portion of its properties and believes that it has satisfactory title to its producing properties in accordance with standards generally accepted in the industry. OilOur oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens thatwhich we believe do not materially interfere with the use of or affect theour carrying value of the properties.

Seasonal NatureWe believe that we have satisfactory title to all of Business

Seasonal weather conditionsour material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and lease stipulations can limit the drillingcontract terms and producing activitiesrestrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other operationsburdens, easements, restrictions and minor encumbrances customary in regionsthe oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficientrights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Natural Gas Dedication Agreements

We have dedicated our natural gas production from the oil and natural gas properties contributed by Citizen under an agreement with a third party. Under this dedication agreement, we are required to deliver our natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.

For the oil and natural gas properties contributed by Linn, we assumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires us to deliver our natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.5% to 25.0%, resulting in a net revenue interest to us generally ranging from 74% to 81% of our working interest, with an average net revenue interest of 78.9%.

Regulation of the U.S. in which LINN operates. These seasonal conditions can pose challenges for meeting the well drilling objectivesOil and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, LINN’s operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.Natural Gas Industry

The demand for natural gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations.

Index to Financial Statements

Environmental Matters and Regulation

LINN’sOur operations are subject to stringentsubstantially affected by federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relatingregulations. Failure to environmental protection. LINN’s operations are subject to the same environmentalcomply with applicable laws and regulations as other companiescan result in the oil and natural gas industry. These laws and regulations may:

require the acquisition of various permits before drilling commences;

require the installation of expensive pollution control equipment;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

limit or prohibit drilling activities on lands lying within wilderness, wetlands, areas inhabited by endangered species and other protected areas;

require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

impose substantial liabilities for pollution resulting from operations; and

with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the production rate of oil, natural gas and NGL below the rate that would otherwise be possible.penalties. The regulatory burden on the industry increases the cost of doing business and consequently affects profitability. Additionally, CongressHistorically, our compliance costs have not had a material adverse effect on our results of operations; however, we are unable to predict the future costs or impact of compliance. Additional proposals and federal and state agencies frequently revise environmental laws and regulations, and any changesproceedings that result in more stringent and costly waste handling, disposal and cleanup requirements foraffect the oil and natural gas industry could have a significant impact on operating costs.are regularly considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Regulation Affecting Production

The environmental laws and regulations applicable to LINN and its operations include, among others, the following U.S. federal laws and regulations:

Clean Air Act, and its amendments, which governs air emissions;

Clean Water Act, which governs discharges to and excavations within the watersproduction of the U.S.;

Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);

Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures;

National Environmental Policy Act, which governs oil and natural gas is subject to U.S. federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions

in which we own or operate producing properties have statutory provisions regulating the exploration for and production activities on federal lands;

Resource Conservationof oil and Recovery Act (“RCRA”),natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which governs the management of solid waste;

Safe Drinking Water Act, which governs the underground injectionwells are drilled, sourcing and disposal of wastewater; and

U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

Various states regulatewater used in the drilling for,and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production gatheringfrom fields and individual wells. These laws and regulations may limit the amount of oil and natural gas we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGLs and natural gas and NGL, including imposing production taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both.within its jurisdiction. States do not regulate wellhead prices or

Index to Financial Statements

engage in other similar direct economic regulations,regulation, but there can be no assurance that they will not do so in the future. The effect of thesesuch future regulations may be to limit the amounts of oil and natural gas and NGL that may be produced from LINN’sour wells, and tonegatively affect the economics of production from these wells or limit the number of wells or locations itwe can drill.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. Our competitors in the oil and natural gas industry is alsoare subject to compliancethe same regulatory requirements and restrictions that affect our operations.

Regulation Affecting Sales and Transportation of Commodities

Sales prices of oil, natural gas, condensate and NGLs are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the U.S. Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil, natural gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to certain state and federal reporting requirements.

The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of natural gas produced by us, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for natural gas production, if any, of the drilling program and the cost of such capacity. Further state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.

The FERC regulates interstate natural gas pipeline transportation rates and service conditions. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. The stated purpose of many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.

In addition to the regulation of natural gas pipeline transportation, FERC has jurisdiction over the purchase or sale of natural gas or the purchase or sale of transportation services subject to FERC’s jurisdiction pursuant to

the EPAct 2005. Under the EPAct 2005, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the NGA to use any deceptive or manipulative device or contrivance in connection with variousthe purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act of 1978 up to $1.0 million per day, per violation. The anti-manipulation rule applies to activities of otherwise non jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under FERC Order No. 704 (defined below).

In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”). Under Order No. 704, any market participant, including a producer that engages in certain wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to the formation of price indices. Not all types of natural gas sales are required to be reported on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 is intended to increase the transparency of the wholesale natural gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.

The FERC also regulates rates and terms and conditions of service on interstate transportation of liquids, including NGLs, under the Interstate Commerce Act, as it existed on October 1, 1977 (“ICA”). Prices received from the sale of liquids may be affected by the cost of transporting those products to market. The ICA requires that certain interstate liquids pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

The rates charged by many interstate liquids pipelines are currently adjusted pursuant to an annual indexing methodology established and regulated by FERC, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goodsplus-1.23%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by obtaining market based rate authority (demonstrating the pipeline lacks market power), establishing rates by settlement with all existing shippers, or through a cost of service approach (if the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology). Increases in liquids transportation rates may result in lower revenue and cash flows for us.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity or for new shippers. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to

us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Rates for intrastate pipeline transportation of liquids are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.

In addition to FERC’s regulations, we are required to observe anti market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to approximately $1.2 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of approximately $1.1 million or triple the monetary gain to the person for each violation.

Regulation of Environmental and Occupational Safety and Health Matters

Our operations are subject to stringent and complex federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge and disposal of materials into the environment and the protection of the environment and natural resources (including threatened and endangered species and their habitat). Numerous governmental entities, including the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and laws. Somethe permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of thosepermits to conduct exploration, drilling, water withdrawal, wastewater disposal and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be disposed or released into the environment or injected into formations in connection with oil and natural gas drilling and production activities, and the manner of any such disposal, release, or injection; (iii) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas, or require formal mitigation measures in such sensitive areas; (iv) require investigatory and remedial measures to mitigate pollution from former andon-going operations, such as requirements to close pits and plug abandoned wells; (v) impose specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws relateand regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.

The trend in environmental regulation has been to occupational safety, resource conservationplace more restrictions and equal opportunity employment.

LINN believeslimitations on activities that it substantially complies with all current applicablemay affect the environment, and thus any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that continuedwe will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

Continued compliance with existing requirements is not expected to materially affect us. However, there is no assurance that we will not incur substantial costs in the future related to revised or additional environmental laws and regulations that could have a material adverse effect on our business and operating results.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws and regulations, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on its financial condition orour capital expenditures, results of operations. Future regulatory issues that could impact LINN include newoperations or financial position.

Hazardous Substances and Wastes

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous andnon-hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or legislation regulating greenhouse gas emissions, hydraulic fracturing and air emissions.

Climate Change

In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warmingall of the Earth’s atmosphere, the EPA has adopted regulations under existing provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the federal Clean Air Act that would require a reduction in emissions of greenhouse gases (“GHG”) from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has asserted that the final motor vehicle GHG emission standards triggered construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, the EPA issued a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process,other wastes associated with the largest sources first subject to permitting. In addition, on November 8, 2010, the EPA finalized new GHG reporting requirements for upstream petroleumexploration, development, and natural gas systems, which will be added to the EPA’s existing GHG reporting rule published in 2009. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will now be required to report annual GHG emissions to the EPA, with the first report due on September 28, 2012. In addition, both houses of Congress have considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. greenhouse gases could require LINN to incur increased operating costs, and could have an adverse effect on demand for oil and natural gas.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas, regulatory programs.if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringentnon-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified asnon-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additivesand environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the Safe Drinking Water Act’s Underground Injection Control Program and has begunregulations is not necessary. The agency missed the process of drafting guidance documents related to this newly asserted regulatory authority. Moreover, on November 23, 2011,deadline, although review may still be ongoing. If the EPA announcedproposes a rulemaking, the consent decree requires that it was granting,EPA take final action by no later than July 15, 2021. Any such change could result in part, a petition to initiate rulemaking underan increase in our as well as the Toxic Substances Control Act (“TSCA”), relating to chemical substances and mixtures used in oil and natural gas exploration and production industry’s costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or production.legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release of a hazardous substance occurred and anyone who disposed or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, legislation hasit is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own, lease, or operate numerous properties that have been introduced before Congressused for oil, natural gas and NGL exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or

operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to provide for federal regulationCERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of hydraulic fracturingpreviously disposed substances and wastes, cleanup of contaminated property or performance of remedial operations to require disclosureprevent future contamination, the costs of which could be substantial.

Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the chemicals usedUnited States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the fracturing process. If adopted, these bills could resultevent of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties fornon-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The CWA also prohibits the discharge of dredge and fill material in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirementsregulated waters, including wetlands, unless authorized by permit. The EPA and restrictions could result in delays in operations at well sites and also increased coststhe U.S. Army Corps of Engineers (“Corps”) published a final rule attempting to make wells productive.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an

Index to Financial Statements

administration-wide review of hydraulic-fracturing practices, and a committeeclarify the federal jurisdictional reach over waters of the United States House(“WOTUS”). Several legal challenges to the rule followed, along with attempts to stay implementation of Representatives has conducted an investigationthe WOTUS rule following the change in U.S. presidential administrations. Currently, the WOTUS rule is active in 22 states and enjoined in 28 states. However, in December 2018, the EPA and USACE proposed changes to regulations under the CWA that would provide discrete categories of hydraulic-fracturing practices. Furthermore,jurisdictional waters and tests for determining whether a numberparticular waterbody meets any of those classifications. Several groups have already announced their intent to challenge the proposed WOTUS replacement rule. Therefore, the scope of jurisdiction under the CWA is uncertain at this time. To the extent either rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties fornon-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The primary federal agencies are analyzing,law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain responsible parties related to the prevention, containment and cleanup of oil spills and damages resulting from such spills in or have been requestedthreatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees, use secondary containment systems to review,prevent spills from reaching nearby water bodies and provide varying degrees of financial assurance. The OPA subjects owners and operators of vessels, offshore facilities, and onshore facilities to strict, joint and several liability for oil removal costs and natural resource damages as well as a variety of environmental issues associated with hydraulic fracturing. The EPA has commencedpublic and private damages that may result from oil spills. Although defenses exist, they are limited. As such, a studyviolation of the OPA has the potential environmental effectsto adversely affect our operations.

Subsurface Injections and Induced Seismicity

In the course of hydraulic fracturing on drinkingour operations, we produce water in addition to oil, natural gas and groundwater, with initial results expectedNGLs. Water that is not recycled may be disposed of in disposal wells, which inject the produced water intonon-producing subsurface

formations. Underground injection operations are regulated pursuant to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. These on-going or proposed studies, depending on their course and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturingUnderground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program includes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resources and imposition of liability by third parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or other regulatory mechanisms. Moreover,the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations.

Furthermore, in response to recent seismic events near belowground disposal wells used for the injection of produced water resulting from oil and gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, regulationsadditional requirements related to produced water disposal wells to improve seismic safety. For example, in Oklahoma, the OCC has implemented a variety of measures including the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has rules requiring operators of certain saltwater disposal wells in the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC, from time to time, has developed and implemented plans calling for wells within areas of interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents. For example, in February 2018 the OCC revised well completion seismicity guidelines to reduce the threshold of seismic readings required to suspend hydraulic fracturing operations in certainsome circumstances. For example, both TexasIn addition, these seismic events have also led to an increase in tort lawsuits filed against exploration and Louisianaproduction companies as well as the owners of underground injection wells.

Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of produced water into disposal wells continues as governmental authorities consider new and/or past seismic incidents in areas where produced water disposal activities occur or are proposed to be performed. The adoption of any new laws, regulations, or directives that restrict our ability to dispose of water generated by production and development activities, whether by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have adopted disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic fracturing fluids. Any such added regulation in states where LINN operates could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect LINN’s revenuesa material adverse effect on our business, financial condition, and results of operations.

Endangered Species Act

The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered and threatened species or their habitats. Some of LINN’s operations may In addition, we could be located in areas that are designated as habitat for endangered or threatened species. LINN believes that it is currently in substantial compliance with the ESA. However, the designation of previously unprotected species as being endangered or threatened could cause LINN to incur additional costs or become subject to operating restrictionsthird-party lawsuits alleging damages resulting from seismic events that occur in our areas where the species are known to exist.of operation.

Air Emissions

On April 17, 2012,The CAA and comparable state laws restrict the Environmental Protection Agency (“EPA”)emission of air pollutants from many sources, such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtainpre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the

potential to delay or limit the development of oil and natural gas projects. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the NAAQS for ground level ozone from the current standard of 75 ppb for the current 8 hour primary and secondary ozone standards to 70 ppb for both standards, and completedattainment/non-attainment designations in July 2018. States are expected to implement more stringent permitting and pollution control requirements as a result of this final rule, which could apply to our operations. While the EPA has determined that all counties in which we operate are in attainment with the new ozone standards, these determinations may be revised in the future. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new facilities or modify existing facilities in these newly designatednon-attainment areas. In another example, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant.

Climate Change

In response to findings that subjectemissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain onshore and offshore oil and natural gas production, processing, transmission and storage operationsfacilities in the United States.

There has not been significant activity in the form of federal legislation to regulation underreduce GHG emissions in recent years. In the absence of such federal climate legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The EPA has also developed strategies for the reduction of methane emissions, including emissions from the oil and gas industry. For example, in June 2016, the EPA published New Source Performance Standards (“NSPS”) Subpart OOOOa requirements to reduce methane and National Emission Standards for Hazardous Air Pollutantsvolatile organic compound (“NESHAP”VOC”) programs. The EPA rules include NSPS standards for completions of hydraulically fracturedemissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas wells. These standards requiresource category, including production, processing, transmission and storage activities. Following the change in presidential administration, there have been attempts to modify these regulations, and litigation concerning the regulations is pending. In addition, the Bureau of Land Management (“BLM”) finalized a similar rule regarding the control of methane emissions in November 2016 that priorapplies to January 1, 2015 owners/operators reduce VOCoil and natural gas exploration and development activities on public and tribal lands. In September 2018, the BLM issued a final rule rescinding the agency’s 2016 methane rule, and litigation challenging the rescission is pending. As a result of the developments described above, substantial uncertainty exists with respect to implementation of the EPA and BLM methane rules. However, given the long-term trend towards increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from naturaloil and gas production activities.

On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not sentimpose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United

States’ adherence to the gathering line during well completion eitherexit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not possible at this time to predict how new laws or regulations in the United States or any legal requirements imposed by flaring using a completion combustion devicethe Paris Agreement on the United States, should it not withdraw from the agreement, that may be adopted or by capturing the gas using green completionsissued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with a completion combustion device. Beginning January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wellsour operations as well as existing wellsresult in delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is a practice in the oil and natural gas industry that is used to stimulate production of oil and natural gas from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting and separately an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. Also, the BLM finalized rules in March 2015, establishing stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, in December 2017, the BLM issued a final rule repealing the 2015 hydraulic fracturing rule. Litigation regarding this rescission is pending.

From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, but, at this time, federal legislation related to hydraulic fracturing appears unlikely. At the state level, some states, including Oklahoma, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure, operational or well construction requirements on hydraulic fracturing activities, or that prohibit hydraulic fracturing altogether. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state or federal level, we may incur additional costs to comply with such requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

In addition to asserting regulatory authority, certain government agencies have conducted reviews focusing on environmental issues associated with hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water

resources “under certain limited circumstances.” Because the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

Endangered Species and Migratory Birds Considerations

The ESA, and comparable state laws were established to protect endangered and threatened species and their habitat. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”). We may conduct operations on oil and natural gas leases in areas where certain species that are refractured. Further,listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the finalizedESA may exist. For example, in November 2016, the FWS completed initial reviews of a petition filed by environmental groups to list the Lesser Prairie Chicken as endangered and found substantial information that the petitioned action may be warranted. An assessment of the biological status of the Lesser Prairie Chicken began in 2015, and further action remains pending. Moreover, as a result of a 2011 settlement agreement, the FWS was required to make a determination on listing numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The FWS missed the deadline and continues to review species for listing under the ESA. In addition, the federal government in the past has issued indictments under the MBTA to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities.

However, in December 2017, the Department of Interior issued a new opinion revoking its prior enforcement policy and concluded that an incidental take is not a violation of the MBTA. The identification or designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Occupational Safety and Health

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA’s Emergency Planning and Community Right to Know Act and comparable state statutes and any implementing regulations also establish specific new requirements, effectiverequire that we organize and/or disclose information about hazardous materials used or produced in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. These rules may require changes to our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements foron-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. There can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Employees

As of May 20, 2019, we had 176 full-time employees. We hire independent contractors on anas-needed basis to perform various field and other services. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business, including, the installation of new equipmentbut not limited to, control emissions. LINN is currently evaluating the effect these rules will have on its business.

LINNcommercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. We cannot predict how future environmental laws and regulations may impact its properties or operations. For the year ended December 31, 2011, LINN did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of LINN’s facilities. LINN is not awareoutcome of any environmental issuessuch lawsuits with certainty, but management believes it is remote that pending or claims thatthreatened legal matters will require material capital expenditures during 2012 or that will otherwise have a material adverse impact on itsour financial positioncondition.

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

Employees

As of December 31, 2011, LINN employed approximately 824 personnel. None of the employees are represented by labor unions or covered by any collective bargaining agreement. LINN believes that its relationship with its employees is satisfactory.

Index to Financial Statements

MANAGEMENT

Our business and affairs will be managed by a board of directors.

The following table sets forth specific information for our executive officersthe names, ages (as of May 24, 2019) and directors. Alltitles of our directors are elected annually by, and may be removed by, LINN as the owner of our sole voting share. Executive officers are appointed for one-year terms.executive officers.

 

Name

  Age   

Position with LinnCo

Position with LINN

Mark E. EllisJoseph A. Mills

   5659   Executive Chairman

Joel L. Pettit

63Executive Vice President – Operations and Marketing

Greg T. Condray

50Executive Vice President – Geoscience and Business Development

David M. Edwards

37Chief Financial Officer

Amber N. Bonney

45Vice President and Chief Executive Officer; DirectorAccounting Officer

David C. Treadwell

  Chairman,42Vice President, General Counsel and Chief Executive Officer; Corporate Secretary

Matthew Bonanno

40Director

Evan Lederman

39Director

Kolja RockovJohn V. Lovoi

58Director

Paul B. Loyd, Jr.

72Director

Michael P. Raleigh

62Director

Andrew Taylor

   41   Executive Vice President and Chief Financial OfficerExecutive Vice President and Chief Financial Officer
Director

Arden L. Walker, Jr. Anthony Tripodo

   52Executive Vice President and Chief Operating OfficerExecutive Vice President and Chief Operating Officer

Charlene A. Ripley

48Senior Vice President and General CounselSenior Vice President and General Counsel

David B. Rottino

46Senior Vice President and Chief Accounting OfficerSenior Vice President of Finance, Business Development and Chief Accounting Officer

George A. Alcorn

80Independent DirectorIndependent Director

David D. Dunlap

50Independent DirectorIndependent Director

Terrence S. Jacobs

69Independent DirectorIndependent Director

Michael C. Linn

6066   DirectorFounder and Director

Joseph P. McCoy

61Independent DirectorIndependent Director

Jeffrey C. Swoveland

57Independent DirectorIndependent Director

Mark E. Ellis is our Chairman, President and Chief Executive Officer andJoseph A. Mills has served in such capacity since April 2012. Mr. Ellis was appointed toon our board of directors since November 2018. Mr. Mills was appointed as Executive Chairman and will serve as the principal executive officer, in April 2012. Heeach case, on an interim basis until his respective successor is alsoappointed. Mr. Mills currently serves as the Chairman, President and Chief Executive Officer of LINNSamson Resources II, LLC, a privately held exploration and production company with assets located in the Powder River Basin and Green River Basin of Wyoming, a position he has held since February 2017. Prior to joining Samson Resources II, LLC, Mr. Mills served as a director of CUI Global, Inc. (NASDAQ: CUI) from August 2015 to October 2016 and served as Chairman and Chief Executive Officer of Eagle Rock Energy G&P, LLC, the general partner of the general partner of Eagle Rock Energy Partners, L.P. (NASDAQ: EROC), from May 2007 until it merged with Vanguard Natural Resources, LP (NASDAQ: VNR) in such capacity since December 2011. HeOctober 2015. Mr. Mills also servesserved as Chief Executive Officer and as a manager of Montierra Management LLC (“Montierra”), which is the general partner of Montierra Minerals & Production, LP, from 2006 to October 2016. From 2003 to 2006, Mr. Mills was the Senior Vice President of Operations for Black Stone Minerals Company, LP, a privately held company. From 2001 to 2003, Mr. Mills was a Senior Vice President of El Paso Production Company, and from 1999 to 2001, Mr. Mills was a Vice President of El Paso Production Company, a wholly owned subsidiary of El Paso Corporation. Prior to joining El Paso, Mr. Mills held various executive and senior-level management positions with Sonat Exploration Company, a wholly owned subsidiary of Sonat, Inc. Mr. Mills holds a Bachelor of Business Administration degree in Petroleum Land Management from the University of Texas, Austin and a Master of Business Administration degree in Finance from the University of Houston.

The board of directors believes that Mr. Mills’ background in the energy industry and experience serving on the board of LINN,directors of other energy companies bring valuable leadership and insight to which he was appointed in January 2010. He previouslythe board of directors and the Company.

Joel L. Pettithas served as our Executive Vice President Chief– Operations and Marketing since September 2018 and as the Executive OfficerVice President – Operations and DirectorMarketing of LINN from January 2010Roan LLC since November 2017. Prior to December 2011. From December 2007 to January 2010,that, Mr. EllisPettit served as Presidentan executive consultant from May 2016 to October 2017, and Chief Operating Officeras the Division Operations Manager of LINNboth theMid-continent Division and the Permian Division of EOG Resources, Inc. from December 2006 to December 2007,April 2017. Mr. EllisPettit has more than 35 years of experience in the oil and gas industry, 22 of which were spent at Pennzoil where he served in a variety of technical roles, including Operations Engineer and Manager. Mr. Pettit graduated from Mississippi State University where he earned a Bachelor of Science degree in Petroleum Engineering.

Greg T. Condray has served as our Executive Vice President—Geoscience and Business Development since September 2018 and as Executive Vice President – Geoscience and Business Development of Roan LLC since November 2017. Mr. Condray has 22 years of experience in the oil and gas industry, having previously worked as Division Exploration Manager in theMid-Continent Division for EOG Resources, Inc. from October 2013 to April 2017, where he was instrumental in assembling its position in the Merge area of Oklahoma. From September 2006 to October 2013 he worked at Chesapeake Energy Corporation, where he was responsible for the exploration of their Eagleford shale play and the development of their Haynesville and Powder River Basin assets, and from May 2017 until he joined us, he had been evaluating potential opportunities. Mr. Condray graduated from the University of Alabama where he earned a Master of Science and Bachelor of Science degree in Geology.

David M. Edwards has served as our Chief OperatingFinancial Officer since September 2018 and as Chief Financial Officer of LINN.Roan LLC since June 2018. Prior to joining us, Mr. Ellis serves on the boards of America’s Natural Gas Alliance, Houston Museum of Natural Science, The Cynthia Woods Mitchell Pavilion, Industry Board of Petroleum Engineering at Texas A&M University and the Visiting Committee of Petroleum Engineering at the Colorado School of Mines.

Kolja Rockov is an ExecutiveEdwards served as Senior Vice President and Chief Financial Officer of LinnCoTapstone Energy Inc. and has served in such capacity since April 2012.its affiliates from October 2014 to June 2018. Mr. Rockov isEdwards also an Executive Vice President and the Chief Financial Officer of Linn Energy, LLC and has served in such capacity since March 2005. Mr. Rockov has more than 15 years of experience in the oil and natural gas finance industry. From October 2004 until he joined LINN in March 2005, Mr. Rockov served as a Managing Director in the Energy Group at RBC Capital Markets, where he was primarily responsible for investment banking coverage of the U.S. exploration and production sector. Mr. Rockov is a member of the Board of Small Steps Nurturing Center in Houston.

Arden L. Walker, Jr. is an Executive Vice President of LinnCo and has served in such capacity since April 2012. Mr. Walker is also an Executive Vice President and the Chief Operating Officer of Linn Energy, LLC and has

Index to Financial Statements

served in such capacity since January 2011. From January 2010 to January 2011, Mr. Walker served as Senior Vice President of Finance of Tapstone Energy, LLC from April 2014 to October 2014. Prior to joining Tapstone Energy, LLC, Mr. Edwards held various roles in the Finance department of SandRidge Energy, Inc. from October 2010 to February 2014. From 2007 until 2010, Mr. Edward worked in Equity Research at UBS Investment Bank, covering publicly traded companies in the Energy sector. Mr. Edwards holds a Bachelor of Science degree in Applied Mathematics from Brown University.

Amber N. Bonney has served as our Chief Accounting Officer since September 2018 and has served as a Vice President since February 2019 and as the Chief OperatingAccounting Officer of Linn Energy, LLC. Mr. Walker joined of Linn Energy,Roan LLC in February 2007 as Senior Vice President—Operations and Chief Engineersince January 2018. Prior to oversee its Texas, Oklahoma and California operations. He is currently responsible for oversight of LINN’s operations in all regions. From April 2006 until he joined LINN in February 2007, Mr. Walkerjoining us, Ms. Bonney served as Asset Development Manager, San Juan Business Unit,the Controller for ConocoPhillips Company. From June 2004Permian Resources, LLC, an Oklahoma City-based private company focused on the acquisition and development of unconventional oil and natural gas resources in the Permian Basin, from November 2015 to April 2006, Mr. WalkerDecember 2017. Prior to her employment with Permian Resources, LLC, Ms. Bonney served as General Manager, Asset Development,the Vice President of Accounting from February 2015 to November 2015 and the Director of Financial Reporting from May 2014 to February 2015 at New Source Energy Partners, LP. New Source Energy Partners, LP filed for liquidation under Chapter 7 of the United States Bankruptcy Code in March 2016. Prior to that, Ms. Bonney served in various capacities, including as controller, at SandRidge Energy, Inc. from March 2008 until May 2014. Ms. Bonney also worked in the San Juan Division for Burlington Resources. Mr. Walkerinternal audit group at Devon Energy Corporation and was a manager at PricewaterhouseCoopers LLP prior to her time at SandRidge Energy, Inc. Ms. Bonney received her Bachelor of Business Administration degree in Accounting and Finance from the University of Oklahoma. Ms. Bonney is also a member of the Society of Petroleum Engineers and Independent Petroleum Association of America. He currently serves on the Board of Directors for the Sam Houston Area Council of the Boy Scouts of America and Theatre Under The Stars.Certified Public Accountant.

Charlene A. Ripley is a Senior Vice President and theDavid C. Treadwellhas served as our General Counsel and Corporate Secretary of LinnCosince September 2018 and has served in that position since April 2012. She is alsoas a Senior Vice President since February 2019. Mr. Treadwell previously served as a consultant toPatterson-UTI Energy Inc. from May 2017 to November 2017, where he provided legal and managerial assistance during the General Counsel and Corporate Secretary of Linnmerger transition afterPatterson-UTI acquired Seventy Seven Energy LLC and has served in that position since April 2007.Inc. Prior to joining LINN, Ms. Ripley held the position of Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer at Anadarko Petroleum Corporation from 2006 until April 2007 andthat, he served as Senior Vice President, General Counsel and Corporate Secretary of Seventy Seven Energy Inc. upon consummation of itsspin-offfrom 2004Chesapeake Energy Corporation in June 2014. From June 2011 to June 2014, Mr. Treadwell served as Lead Counsel and then as Vice President – Legal and Chief Counsel at Chesapeake Energy Corporation. Mr. Treadwell also served as General Counsel of Bronco Drilling Company, Inc. from July 2007 until 2006. Ms. Ripley currently chairsit was acquired by Chesapeake Energy Corporation in June 2011. Prior to joining the OilCompany, Mr. Treadwell was evaluating potential opportunities from November 2017 until August 2018. Mr. Treadwell holds a Juris Doctorate, with highest honors, from the University of Oklahoma College of Law and Gas Practice Committeea Bachelor of Science degree in Finance from the University of Illinois at Urbana-Champaign.

Matthew Bonanno has served on our board of directors since September 2018. Mr. Bonanno joined York Capital Management (“York”) in July 2010 and is a Partner of the Institute for Energy Lawfirm. Mr. Bonanno joined York from the Blackstone Group, where he worked as an associate focusing on restructuring, recapitalization and servesreorganization transactions. Prior to joining the Blackstone Group, Mr. Bonanno worked on the board of the Texas General Counsel Forum.financing and strategic transactions at News Corporation and as an investment banker at JP Morgan and Goldman Sachs. In addition Ms. Ripley serves on the advisory boards of the Women’s Energy Network and Executive Women’s Partnership of the Greater Houston Partnership and serves on several nonprofit boards including the Impact Youth Development Center, Girls Inc. and the American Heart Association of Houston. Sheto Roan,

Mr. Bonanno, in his capacity as a York employee, is alsocurrently a member of the United Wayboards of Greater Houston Women’s Initiative.

David B. Rottino is a Senior Vice PresidentRiviera, Rever Offshore AS, Samson Resources II, LLC, all entities incorporated pursuant to York’s partnership with Costamare Inc., NextDecade Corp. and the Chief Accounting Officer of LinnCo and has served in that position since April 2012. He is also the Senior Vice President of Finance, Business Development and Chief Accounting Officer of Linn Energy, LLC and has served in that position since July 2010. From June 2008 to July 2010, Mr. Rottino served as the Senior Vice President and Chief Accounting Officer of Linn Energy, LLC. He served as Vice President and E&P Controller for El Paso Corporation from June 2006 to May 2008.Vantage Drilling Co. Prior to joining El Paso Corporation,the Reorganization, Mr. Rottino served as Assistant Controller for ConocoPhillips from April 2006 to June 2006. HeBonanno was Vice President and Chief Financial Officer for the Canadian division of Burlington Resources from July 2005 to April 2006. Mr. Rottino is a Certified Public Accountant and a member of the American Instituteboards of Certified Public AccountantsRoan LLC and Texas Society of Certified Public Accountants. In addition, he currently serves on the Board of Camp for All.

George A. Alcorn was appointed to our Board of Directors in April 2012. Mr. Alcorn is an independent director. Mr. Alcorn also serves on the board of LINN, to which he was appointed in January 2006, and is Chairman of LINN’s Nominating and Governance Committee. Mr. Alcorn has served as President of Alcorn Exploration, Inc., a private exploration and production company, since 1982. Mr. AlcornNew Linn. He is also a member of the board of directors of EOG Resources, Inc. He isthe Children’s Scholarship Fund. Mr. Bonanno received a past chairmanBachelor degree in History from Georgetown University and a Master of Business Administration degree in finance from The Wharton School of the Independent Petroleum AssociationUniversity of America and a founding member and past chairman of the Natural Gas Council.Pennsylvania.

Mr. Dunlap was appointed to our Board of Directors in May 2012. Mr. Dunlap is an independent director. Mr. Dunlap also serves on the board of LINN, to which he was appointed in May 2012. Mr. Dunlap has served as Chief Executive Officer, since April 2010, and President, since February 2011, of Superior Energy Services, Inc. From 2007 until April 2010, Mr. Dunlap served as Executive Vice President—Chief Operating Officer of BJ Services Company, a well services provider. Mr. Dunlap also currently serves on theThe board of directors of Superior Energy Services, Inc.

Terrence S. Jacobs was appointedbelieves Mr. Bonanno’s extensive investment and restructuring experience in the energy industry brings valuable strategic and analytical skills to our Boardboard of Directors in April 2012.directors.

Evan Lederman has served on our board of directors since September 2018. Mr. JacobsLederman is an independent director. Mr. Jacobs also servesa Managing Director,Co-Head of Restructuring and Partner on the Investment Team at Fir Tree Partners. Mr. Lederman focuses on the funds’ distressed credit and special situation investment strategies, includingco-managing its energy restructuring initiatives. Prior to joining Fir Tree Partners in 2011, Mr. Lederman worked in the Business Finance and Restructuring groups at Weil, Gotshal & Manges LLP and Cravath, Swaine & Moore LLP. In addition to Roan, Mr. Lederman, in his capacity as a Fir Tree Partners employee, is currently a member of the boards of Riviera, Ultra Petroleum Corp. (Chairman), Amplify Energy Corp., New Emerald Energy LLC, and Deer Finance, LLC. Prior to the Reorganization, Mr. Lederman was a member of the boards of Roan LLC and New Linn. Mr. Lederman received a Juris Doctorate degree with honors from New York University School of Law and a Bachelor of Arts, magna cum laude, from New York University.

The board of LINN, to which he was appointed in January 2006.directors believes Mr. Jacobs has servedLederman’s considerable experience as LINN’s Lead Director since January 2012. Since 1995, Mr. Jacobs has served as President and CEOa member of Penneco Oil Company, which provides ongoing leasing, marketing, exploration and drilling operations for natural gas and crude oil in Pennsylvania, West Virginia and Wyoming. Mr. Jacobs currently serves on the boards of directors of Penneco Oil Companyexploration and affiliates, CMS Mid-Atlantic, Inc.,production companies, as well as his extensive investment and restructuring experience in the Pennsylvania

energy industry, his brings valuable strategic and analytical skills to our board of directors.

Index to Financial Statements

Independent OilJohn V. Lovoi has served on our board of directors since September 2018. Mr. Lovoi is the founder of JVL Advisors, LLC, a Houston based asset manager specializing in upstream oil and Gas Association and Duquesne University. Mr. Jacobs served as President of the Independent Oil and Gas Association of Pennsylvania from 1999 to 2001 and from 2003 to 2005gas investments, and has served as a director of the Independent Petroleum Association of America for the states of Delaware, Maryland, Pennsylvania and New York—West from 2000-2006. Hemanaging partner since it was founded in 2003. Mr. Lovoi is asole member of, and exercises investment management control over, JVL, an entity that may be deemed to beneficially own all securities held by Roan Holdings through its indirect majority ownership interest in Roan Holdings and its contractual right to nominate a majority of Roan Holdings’ board of managers, which exercises voting and dispositive power over all securities held by Roan Holdings. Mr. Lovoi has approximately 30 years of experience in oil and gas research, investment banking and investments. Prior to forming JVL in 2003, he was the National Petroleum Council,head of Morgan Stanley’s oil and gas investment banking practice. Prior to this role, he is presently servingserved as the head of Morgan Stanley’s oil and gas equity research practice. Mr. Lovoi currently serves as Chairman of the Tax Committee of the Independent Petroleum Association of America. Mr. Jacobs is a Certified Public Accountant in Pennsylvania.

Michael C. Linn was appointed to our Board of Directors in April 2012. He is also the Founder of LINN and has served as a Director of LINN since December 2011. Prior to that, he was Executive Chairman of the Board of Directors of LINN since January 2010. He served as Chairman and Chief Executive Officer of LINN from December 2007 to January 2010; Chairman, President and Chief Executive Officer of LINN from June 2006 to December 2007; and President, Chief Executive Officer and Director of LINN from March 2003 to June 2006. Following his retirement as an officer of LINN, Mr. Linn formed MCL Ventures LLC, a private investment vehicle that will focus on purchasing oil and gas royalty as well as non-operated interests in oil and gas wells, subject to the non-competition provisions in his retirement agreement with LINN. Mr. Linn serves on the National Petroleum Council and Natural Gas Council. He serves on the board of the Independent Petroleum Associationdirectors for Dril-Quip, Inc, a leading provider of America (IPAA)highly engineered offshore drilling products and is Chairman of the IPAA Political Action Committeeservices, and past Chairman of IPAA. He serves as the Texas Representative for the Legal and Regulatory Affairs Committee of the Interstate Oil and Gas Compact Commission. He previously served as Chairman of the National Gas Council and Director of the Natural Gas Supply Association. He is former President of the Independent Oil and Gas Associations of New York, Pennsylvania and West Virginia. His civic affiliations include serving on the boards of the Texas Heart Institute, Museum of Fine Arts, Houston, Texas Children’s Hospital, Houston Children’s Charity, Houston Police Foundation and on the Visitors Board of the MD Anderson Cancer Center. He is the Chairman of the Texas Children’s Hospital Compensation Committee. In February 2012, Mr. Linn joined the board of directors for Epsilon Energy, an integrated upstream and midstream company in the Marcellus Shale. Mr. Lovoi is also a director of Nabors Industries Ltd.

Joseph P. McCoy was appointedHelix Energy Solutions, a leading global provider of well intervention equipment and services to our Board of Directors in April 2012.the global offshore oil and gas industry and Mr. McCoy isLovoi served as an independent director of Jones Energy, Inc., an oil and will serve as Chairman of our Audit Committee. Mr. McCoy also serves on the board of LINN, to which he was appointed ingas company, from February 2018 until September 2007, and is Chairman of LINN’s Audit Committee. Mr. McCoy served as Senior Vice President and Chief Financial Officer of Burlington Resources Inc. from 2005 until 2006 and Vice President and Controller (Chief Accounting Officer) of Burlington Resources Inc. from 2001 until 2005.2018. Prior to joining Burlington Resources,the Reorganization, Mr. McCoy spent 27 years with Atlantic Richfield and affiliates in a variety of financial positions. Mr. McCoy joined the Board of Directors of Global Geophysical Services, Inc. and Scientific Drilling International during 2011 and served asLovoi was a member of the board of Roan LLC. Mr. Lovoi received a Bachelor of Science degree in Chemical Engineering from Texas A&M University and received his Master of Business Administration with an emphasis on finance and accounting from the University of Texas at Austin.

The board of directors believes that Mr. Lovoi’s background in investment banking, as well as hisin-depth knowledge of Rancher Energy, Inc.the oil and BPI Energy Corp. from 2007gas industry generally, qualifies him to 2009. Since 2006, other than his serviceserve as a member of our board of directors.

Paul B. Loyd, Jr. has served on our board of directors since September 2018. Mr. Loyd served as chairman and chief executive officer of R&B Falcon Corporation, a diversified drilling company, until 2001 when it merged with Transocean Sedco Forex. Prior to his tenure at R&B Falcon Corporation, Mr. Loyd accumulated more than 30 years of experience in the energy and energy services industry. He began his career in 1969 with Reading & Bates Offshore Drilling Company, holding various positions both in the United States and overseas,

primarily West Africa, the Middle East and the other boards identified above,Far East. He also served with Houston Offshore International, Inc. a domestic offshore drilling company, as Chief Financial Officer, Atwood Oceanics, Inc, an international drilling contractor, as Assistant to the President, Griffin-Alexander, Inc., a domestic drilling contractor, as President, and Chiles-Alexander, Inc., as Chief Executive Officer. Mr. McCoy has been retired.

Jeffrey C. Swoveland was appointedLoyd also founded Carrizo Oil & Gas, Inc. In addition to our Boardthe drilling industry, Mr. Loyd served as a consultant to the Central Planning Organization of Directorsthe Government of Saudi Arabia and assisted in April 2012.writing the Five Year Plan for 1975 – 1980. Mr. Swoveland isLoyd served as an independent director.director of Jones Energy, Inc. from February 2018 until September 2018 and prior to the Reorganization, served on the board of Roan LLC. Mr. Swoveland alsoLoyd serves on the board of LINN,Roan Holdings, a significant stockholder of the Company. Mr. Loyd graduated from Southern Methodist University with a Bachelor of Business Administration in Economics. Cox School of Business honored Mr. Loyd in 2001 with its Distinguished Alumni Award and in 2012 Paul was named an SMU Distinguished Alumni. He received his Master of Business Administration degree from the Harvard Graduate School of Business.

The board of directors believes Mr. Loyd’s significant experience, both in the energy industry broadly and in the Company’s specific areas of operation, qualifies him to which he was appointed in January 2006, and is Chairmanserve as a member of LINN’s Compensation Committee. Since June 2009,our board of directors.

Michael P. Raleighhas served on our board of directors since September 2018. Mr. SwovelandRaleigh has served as chief executive officer and a director for Epsilon Energy Ltd. since July 2013. Before becoming chief executive officer at Epsilon Energy Ltd., he acted in various positions in the Chief Executive Officerglobal oil and gas business for 35 years, primarily holding positions in the areas of ReGear Life Sciences (formerly known as Coventina Healthcare Enterprises), a medical device company that developsreservoir development strategy, property valuations, completions and markets products which reduce pain and increaseproduction. He has also been managing investments with Domain Energy Advisors since January 2005. Prior to the rate of healing through therapeutic, deep tissue heating. From May 2006 to June 2009,Reorganization, Mr. Swoveland served as Chief Operating Officer of ReGear Life Sciences. From 2000 to 2006, he served as Chief Financial Officer of BodyMedia, a life-science and bioinformatics company. From 1994 to 2000, he served as Director of Finance, VP Finance & Treasurer and Interim Chief Financial Officer of Equitable Resources, Inc., a diversified natural gas company. Mr. Swoveland is alsoRaleigh was a member of the board of directors of PDC Energy.

Our Board of Directors

All of our directors currently serve as directors of LINN. We anticipate that we will have an audit committee composed of our four independent directors, Messrs. Alcorn, Jacobs, McCoy and Swoveland, upon the closing of the sale of shares offered by this prospectus.

Index to Financial Statements

Executive Compensation

Our executive officers and employees are also executive officers of, or employed directly by, LINN. LINN will make compensation decisions for, and pay compensation directly to, such individuals, and they will not receive additional compensation from us. As such, we have not paid or accrued any obligations with respect to compensation or benefits for our executive officers or employees. We do not expect to pay any salaries, bonuses or equity awards to such executive officers or employees.

Director Compensation

Officers or employees of Linn Energy, LLC who also serve as our directors will not receive additional compensation. Each independent director will receive an annual fee of $7,500 for his services to us plus $500 for each meeting ofRoan LLC. Mr. Raleigh serves on the board of Roan Holdings, a significant stockholder of the Company. Mr. Raleigh received a Bachelor of Science degree in Chemical Engineering from Queens University in Canada and received his Master of Business Administration degree from the University of Colorado.

The board of directors orbelieves that Mr. Raleigh is qualified to serve as a committeemember of our board of directors as a result of his background in engineering, including reserve, acquisitions and valuation engineering, and his experience in the development and appraisal of oil and gas fields.

Andrew Taylor has served on our board of directors since September 2018. Mr. Taylor is a member of the investment team of Elliott Management Corporation (“Elliott”), a New York-based trading firm, where he is responsible for various corporate investments. Prior to joining Elliott in August 2015, Mr. Taylor was a member of the investment team of BlackRock’s Distressed Products Group from April 2009 to August 2015 and prior to that held similar positions at R3 Capital Partners and the Global Principal Strategies team at Lehman Brothers. In addition to Roan, Mr. Taylor, in his capacity as an Elliott employee, is currently a member of the boards of Riviera and Birch Permian Holdings Inc. Prior to the Reorganization, Mr. Taylor was a member of the boards of Roan LLC and New Linn. Mr. Taylor earned a Bachelor of Science degree in Mechanical Engineering from Rose-Hulman Institute of Technology and a Master of Business Administration, with honors, from the University of Chicago Booth School of Business.

The board of directors believes Mr. Taylor’s considerable experience in the investment advisory industry brings substantial investment management skills to the board of directors of LinnCo that he attends from LINN. In addition, each independent director is reimbursed for out-of-pocket expenses in connection with attending meetings of thedirectors.

Anthony Tripodohas served on our board of directors or committeessince September 2018. Mr. Tripodo has also served as Managing Director of LinnCo. Each director is indemnified by us for actions associated with beingArch Creek Advisors LLC, a director to the full extent permitted under Delaware law.

Security Ownership of Certain Beneficial Owners and Management

financial advisory firm, since January 2018. Prior to this offering, none of our directors or officers have owned any of our shares or voting shares.

The following table sets forthhis time at Arch Creek Advisors LLC, Mr. Tripodo served as of February 14, 2012, the number of LINN units beneficially owned by: (i) each person who is known to LINN to beneficially own more than 5% of a class of units; (ii) the current directors and nominees of LINN’s board of directors; (iii) each of the following 2011 named officers of LINN: Michael C. Linn, LINN’s former Executive Chairman, Mark E. Ellis, LINN’s Chairman,Vice President and Chief Executive Officer, Kolja Rockov, LINN’sSenior Advisor of Helix Energy Solutions Group, Inc. (“Helix”), a provider of well intervention and robotics services for the offshore oil and gas and renewable energy industries, from June 2017 to December 2017 and previously served as Executive Vice President and Chief Financial Officer Arden L. Walker, Jr., LINN’s Executive Vice President and Chief Operating Officer and Charlene A. Ripley, LINN’s Senior Vice President and General Counsel; and (iv) all directors and executive officers of LINN as of February 14, 2012 as a group. LINN obtained certain informationfrom June 2008 to June 2017. Beginning in the table from filings made with the SEC. Unless otherwise noted, each beneficial owner has sole voting power and sole investment power.

Name of Beneficial Owner(1)

  Units
Beneficially
Owned
   Percentage of
Units
Beneficially
Owned
 

Mark E. Ellis(2)(3)(4)

   1,151,410     *  

Kolja Rockov(2)(3)(5)

   747,626     *  

Arden L. Walker, Jr. (2)(3)(6)

   392,118     *  

Charlene A. Ripley(2)(3)(7)

   316,004     *  

George A. Alcorn(2)(3)(8)

   25,615     *  

Terrence S. Jacobs(2)(3)(9)

   248,365     *  

Michael C. Linn(2)(3)(10)

   705,826     *  

Joseph P. McCoy(2)(3)

   29,710     *  

Jeffrey C. Swoveland(2)(3)(11)

   31,615     *  

All executive officers and directors as a group
(10 persons)(12)

   3,881,949     1.95

*Less than 1% of class based on 199,356,143 units outstanding as of the record date.
(1)To LINN’s knowledge after reviewing Schedule 13G/Ds filed with the SEC, LINN is not aware of any holders who beneficially own more than 5% of its units.
(2)The address of each beneficial owner, unless otherwise noted, is c/o Linn Energy, LLC, 600 Travis, Suite 5100, Houston, Texas 77002.
(3)Includes unvested restricted unit awards that vest2003, Mr. Tripodo served in equal installments, generally over approximately three years.

Index to Financial Statements
(4)Includes 360,765 units underlying options currently exercisable. Includes 407,228 units Mr. Ellis has pledged to secure certain personal accounts.
(5)Includes 400 units as custodian under certain Uniform Gifts to Minors Accounts (UGMA) for immediate family members as to which Mr. Rockov disclaims beneficial ownership. Includes 205,225 units Mr. Rockov has pledged to secure certain personal accounts and 368,225 units underlying options currently exercisable.
(6)Includes 153,550 units underlying options currently exercisable.
(7)Includes 142,275 units underlying options currently exercisable.
(8)Includes 2,000 units underlying options currently exercisable.
(9)Includes 4,250 units owned indirectly by Mr. Jacobs as UGMA custodian for immediate family members and 140,000 units owned indirectly by Mr. Jacobs through Penneco Exploration Co LLC, a company of which, through a trust, Mr. Jacobs owns 50% of the voting interests.
(10)Includes 131,500 units underlying options currently exercisable.
(11)Includes 10,000 units underlying options currently exercisable.
(12)Percentage ownership of executive officer and directors is based on total units outstanding as of the record date.

Index to Financial Statements

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Our Relationship with Linn Energy, LLC

General.On the completion of this offering, we will own LINN units representing approximately     % of LINN’s outstanding units. LINN controls our management and operations through its ownership of our sole voting share.

Omnibus Agreement. Concurrent with the closing of this offering, we will enter into an agreement with LINN (the “Omnibus Agreement”) pursuant to which LINN will agree to provide us certain financial, legal, accounting, tax advisory, financial advisory and engineering services or to pay on our behalf or reimburse us for any expenses incurred in connection with securing these services from third parties, as well as printing costs and other administrative and out-of-pocket expenses we incur, along with any other expenses we will incur in connection with this offering or any future offering of our shares or as a result of being a publicly traded entity, including costs associated with annual, quarterly and other reports to our shareholders, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, independent auditor fees and registrar and transfer agent fees. LINN will also provide us with cash management services, including treasury services with respect to the payment of dividends and allocation of reserves for taxes. These cash management services are intended to optimize the use of our cash on hand and to reduce the likelihood of a change in the amount of any dividend paid to our shareholders across periods other than as a result of any change in the amount of distributions paid by LINN. In addition, LINN will indemnify us for damages suffered or costs incurred (other than income taxes payable by us) in connection with carrying out our activities.

Future Offerings. The Omnibus Agreement will require LINN to provide us, pay on our behalf or reimburse us for all expenses incurred in connection with future offerings of our shares, including legal and other expert fees, printing costs and filing fees. We will conduct future offerings of our shares only with an agreement by LINN to sell us a number of LINN units equalother roles at Helix, including director and Chairman of the Audit Committee. Prior to joining Helix in 2003, Mr. Tripodo served in various executive and financial leadership roles with Baker Hughes, Veritas

DGC Inc., Tesco Corporation and as a board member of various other energy companies. He has over 35 years of experience in the global energy industry. Mr. Tripodo also served as a manager during his tenure at the accounting firm of Price Waterhouse & Co., which spanned from 1974 to 1980. Mr. Tripodo holds a Bachelor of Arts degree in Business from St. Thomas University. Pursuant to the numberStockholders’ Agreement, Mr. Tripodo was designated to our board of shares sold in such offering for an amount equaldirectors by Roan Holdings.

The board of directors believes that Mr. Tripodo’s significant energy industry experience, financial expertise and corporate governance experience make him well suited to the net proceeds of such offering. Asserve as a result, LINN will indirectly bear the cost of any underwriting discounts or commissions and expenses associated with future offerings of our shares.

Indemnification of Officers and Directors

Our limited liability company agreement provides that we will generally indemnify officers and membersmember of our board of directors to the fullest extent permitted by the law against all losses, claims, damages or similar events. Our limited liability company agreement is filed as an exhibit to the registration statement. Subject to any terms, conditions or restrictions set forth in our limited liability company agreement, Section 18-108directors.

Board of the Delaware Limited Liability Company Act (the “LLC Act”) empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against all claims and demands whatsoever. We have also entered into individual indemnity agreements with each of our executive officers and directors which supplement the indemnification provisions in our limited liability company agreement.

Directors

Index to Financial Statements

DESCRIPTION OF OUR SHARES

The shares represent limited liability company interests in us. The holders of shares are entitled to receive dividends and exercise the rights or privileges available to shareholders under our limited liability company agreement. Please read “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement.” Upon the completion of this offering, assuming the underwriters do not exercise their option to purchase additional shares, we will have                 shares outstanding.

Voting Rights

The shares you own will not entitle you to vote on the election of our directors. LINN owns the voting share entitled to vote to elect our directors and will elect all of our directors. Owners of our shares will vote only on the specified matters described in “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement—Voting Rights.”

As a holder of LINN units, we will be entitled to vote on all matters on which holders of LINN units are entitled to vote, which provides our shareholders the ability to indirectly influence LINN’s management. We will submit to a vote of our shareholders, as described in “Description of the Limited Liability Company Agreements—Our Limited Liability Company Agreement—Voting Rights,” any matter submitted to us by LINN for a vote of holders of LINN units. We will vote our LINN units in the same manner that our shareholders vote (or refrain from voting) their shares for or against a proposal, including non-votes or abstentions.

Dividends

We will pay dividends on our shares of the cash we receive as distributions in respect of our LINN units, net of reserves for income taxes payable by us within five days after we receive such distributions. If distributions are made on the LINN units other than in cash, we will pay a dividend on our shares in substantially the same form, provided that if LINN makes a distribution on the LINN units in the form of additional LINN units, we would distribute an equal number of additional shares to our shareholders such that, immediately following such distributions, the number of our shares outstanding is equal to the number of LINN units we hold. Our board of directors may choose to withhold somecurrently consists of eight members. Our Class A common stock is traded on the NYSE. Each of Messrs. Tripodo, Bonanno, Lederman, Taylor, Lovoi, Loyd and Raleigh are independent under the independence standards of the cashNYSE. Mr. Mills does not meet the independence standards of the NYSE because of his interim role as Executive Chairman and principal executive officer of the Company.

In evaluating director candidates, we receive as distributions in respect of our LINN units as reserves for income taxes payable by us, which would causehave and will continue to assess whether a candidate possesses the dividendsintegrity, judgment, knowledge, experience, skills and expertise that we pay on our sharesare likely to be less thanenhance the distributions we receive from LINN.

Issuance of Additional Shares

Our limited liability company agreement authorizes us to issue an unlimited number of additional shares and voting shares for the consideration and on the terms and conditions determined by our board of directors withoutdirectors’ ability to manage and direct our affairs and business, including, when applicable, to enhance the approval of our shareholders. Our shareholders will not have preemptive rights to acquire additional shares or our other securities.

Maintenance of Ratio of Shares to Units

Our limited liability company agreement provides that the number of our outstanding shares will at all times equal the number of LINN units we own. If there is a change in the number of LINN units we own, we will issue to all shareholders a share dividend or effect a share split or combination to provide that at all times the number of shares outstanding equals the number of LINN units we own. In the event of a share repurchase, LINN would agree to purchase an equal number of LINN units from us, or take any other such action as may be reasonable, to maintain the one-to-one ratio of shares to LINN units.

Index to Financial Statements

Transfer Agent and Registrar

American Stock Transfer & Trust Company has agreed to act as our transfer agent and will serve as registrar and transfer agent for the shares. We pay all fees charged by the transfer agent for transfers of shares, except for the following fees that will be paid by shareholders:

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

special charges for services requested by a holder of a shares; and

other similar fees or charges.

There will be no charge to holders for disbursements of our cash dividends. We will indemnify the transfer agent, its agents and each of their shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconductability of the indemnified person or entity.

The transfer agent may at any time resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, we are authorized to act as the transfer agent and registrar until a successor is appointed.

Transfer of Shares

By transfer of shares in accordance with our limited liability company agreement, each transferee of shares will be admitted as a shareholder with respect to the shares transferred when such transfer and admission is reflected on our books and records. Additionally, each transferee of shares:

becomes the record holder of the shares;

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed and delivered our limited liability company agreement;

represents that the transferee has the capacity, power and authority to enter into the limited liability company agreement;

grants powers of attorney to our officers and any liquidator of our company as specified in the limited liability company agreement; and

is deemed to have the consents and waivers contained in our limited liability company agreement.

Until a share has been transferred on our books and records, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the share as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Index to Financial Statements

DESCRIPTION OF THE LINN UNITS

The LINN units represent limited liability company interests in LINN. The holders of units are entitled to participate in distributions and exercise the rights or privileges available to unitholders under LINN’s limited liability company agreement. Please read “Description of the Limited Liability Company Agreements—LINN’s Limited Liability Company Agreement.” As of                     , 2012, LINN had                 units outstanding. No other member interests are outstanding.

LINN’s Cash Distribution Policy

LINN must distribute on a quarterly basis all of its available cash to holders of the LINN units. LINN’s limited liability company agreement defines “available cash” as, for each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash reserves established by the LINN board of directors to:

provide for the proper conduct of business (including reserves for future capital expenditures, future debt service requirements, and anticipated credit needs); and

comply with applicable laws, debt instruments or other agreements;

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.

Working capital borrowings are borrowings that will be made under LINN’s revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders. LINN is prohibited from making any distributions to unitholders if it would cause an event of default, or if an event of default is existing, under its credit facility.

LINN’s ability to pay distributions is also subject to restrictions contained in the Credit Facility and the indentures governing its Senior Notes.

Timing of Distributions

LINN pays distributions on its units within 45 days after each March 31, June 30, September 30 and December 31 to unitholders of record on the applicable record date.

Issuance of Additional Units

LINN’s limited liability company agreement authorizes it to issue an unlimited number of additional securities and rights to buy securities for the consideration and on the terms and conditions determined by its board of directors without the approval of the unitholders. It is possible that LINN will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units LINN issues will be entitled to share equally with the then-existing holders of units in its distributions of available cash. In addition, the issuance of additional units or other equity securities may dilute the value of the interests of the then-existing holders of units in LINN’s net assets. In accordance with Delaware law and the provisions of its limited liability company agreement, LINN may also issue additional securities that, as determined by its board of directors, may have special voting rights to which the units are not entitled. The holders of units will not have preemptive rights to acquire additional units or other securities.

Voting Rights

Unitholders have the right to vote with respect to the election of LINN’s board of directors, certain amendments to its limited liability company agreement, the merger of LINN or the sale of all or substantially all of its assets, and the dissolution of LINN. See “Description of the Limited Liability Company Agreements—LINN’s Limited Liability Company Agreement—Voting Rights.”

Index to Financial Statements

Exchange Listing

LINN’s units are traded on The NASDAQ Global Select Market under the symbol “LINE.”

Transfer Agent and Registrar

American Stock Transfer & Trust Company is LINN’s transfer agent and serves as registrar and transfer agent for the units. LINN pays all fees charged by the transfer agent for transfers of units, except for the following fees that will be paid by unitholders:

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

special charges for services requested by a holder of a unit; and

other similar fees or charges.

There will be no charge to holders for disbursements of LINN’s cash distributions. LINN will indemnify the transfer agent, its agents and each of their shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may at any time resign, by notice to LINN, or be removed by LINN. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, LINN is authorized to act as the transfer agent and registrar until a successor is appointed.

Transfer of Units

By transfer of units in accordance with LINN’s limited liability company agreement, each transferee of units will be admitted as a unitholder with respect to the units transferred when such transfer and admission is reflected on LINN’s books and records. Additionally, each transferee of units:

becomes the record holder of the units;

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed LINN’s limited liability company agreement;

represents that the transferee has the capacity, power and authority to enter into the limited liability company agreement;

grants powers of attorney to LINN’s officers and any liquidator of LINN as specified in the limited liability company agreement; and

makes the consents and waivers contained in the limited liability company agreement.

Until a unit has been transferred on LINN’s books, it and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Index to Financial Statements

DESCRIPTION OF THE LIMITED LIABILITY COMPANY AGREEMENTS

The following information and the information included under “Description of our Shares” and “Description of the LINN Units” summarizes the material information contained in our limited liability company agreement and LINN’s limited liability company agreement. For more detailed information, you should read LINN’s limited liability company agreement, which is included as exhibit 3.1 to LINN’s Current Report on Form 8-K filed September 7, 2010 and incorporated by reference as an exhibit to our registration statement filed with the SEC in connection with this offering, and our limited liability company agreement, a copy of which has been filed as an exhibit to our registration statement filed with the SEC in connection with this offering. Please read “Where You Can Find More Information.”

Our Limited Liability Company Agreement

We summarize the following provisions of our limited liability company agreement elsewhere in this prospectus:

with regard to dividends, please read “Description of our Shares—Dividends.”

with regard to issuances of additional shares, please read “Description of our Shares—Issuance of Additional Shares.”

with regard to the transfer of shares, please read “Description of our Shares—Transfer of Shares.”

Organization and Duration

LinnCo was formed in April 2012 and will remain in existence until dissolved, wound up and terminated in accordance with our limited liability company agreement.

Purpose

Our sole purpose is to hold LINN units and to provide for our officers and directors to exercise, at the direction of our shareholders, all the rights of a LINN unitholder under LINN’s Limited Liability Company Agreement and the LLC Act.

U.S. Federal Income Tax Status as a Corporation

We have elected to be treated as a corporation for U.S. federal income tax purposes.

Shareholders

LINN is our founding member and owns our sole voting share. Our other members will be the owners of common shares. LINN, as the holder of our sole voting share, will have the sole right to elect our directors.

Capital Contributions

Shareholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Limited Liability

The LLC Act provides that a shareholder who receives a distribution and knew at the time of the distribution that the distribution was in violation of the LLC Act will be liable to us for the amount of the distribution for three years from the date of the distribution. Under the LLC Act, we may not make a distribution to a shareholder if, after the distribution, all of our liabilities, other than liabilities to shareholders in respect of their shares and liabilities for which the recourse of creditors is limited to specific property of LinnCo, would exceed the fair

Index to Financial Statements

value of our assets. For the purpose of determining the fair value of our assets, the LLC Act provides that the fair value of property subject to liability for which recourse of creditors is limited will be included in our assets only to the extent that the fair value of that property exceeds the nonrecourse liability. Under the LLC Act, an assignee who becomes a shareholder is liable for the obligations of his assignor to make contributions to us, except that the assignee is not obligated for liabilities unknown to him at the time he became a shareholder and that could not be ascertained from our limited liability company agreement.

The Board

Our business and affairs will be managed by a board of directors. Members of the board will be elected, and may be removed, solely by the owner of the voting share. The initial board will consist of seven directors, and its membership at the closing of this offering will be identical to LINN’s board of directors. The authority and functioncommittees of the board of directors will be identical to fulfill their duties. Our directors hold office until the authorityearlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and functions of aqualified.

The board of directors consists of two classes of directors, with Mr. Mills serving a corporation organized underterm ending on the General Corporation Lawdate of the StateCompany’s 2019 annual general meeting of Delaware, or DGCL, althoughstockholders, and each of Messrs. Bonanno, Lederman, Lovoi, Loyd, Raleigh, Taylor and Tripodo serving a term ending on the directors’ fiduciary duties2020 annual meeting. Following the 2020 annual meeting, the board of directors will cease to be limited as described in “—classified and nominations for director shall be made by the board of directors upon the advice of the Company’s nominating and corporate governance committee.

Meetings of the Board of Directors; Fiduciary Duties.”Directors

TheOur board of directors will hold regular and special meetings from time to time and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board from time to time.of directors. Special meetings of the board of directors may be called on one day’swith 24 hours’ notice to each directormember (unless waived) upon request of the chairmanChairman of the board of directors, the chief executive officer, if he is also a director,Chief Executive Officer or upon the written request of any two members of the board of directors. A quorum for a regular or special meeting will exist when a majority of the directorsmembers are participating in the meeting either in person or by conference telephone. Any action required or permitted to be taken at a meeting of the board of directors may be taken without a meeting, without prior notice and without a vote if a majorityall of the directors then in officemembers sign a written consent authorizing the action.

Leadership Structure

The board can establish committees composed of two or more directors determined that Mr. Mills should serve as the Executive Chairman of the board of directors until his respective successor is appointed. Additionally, the board of directors determined that Mr. Tripodo should serve as the lead independent director of the board of directors.

Director Independence

The board of directors reviewed the independence of our directors using the independence standards of the NYSE and, can delegate powerbased on this review, determined that Messrs. Tripodo, Bonanno, Lederman, Lovoi, Loyd, Raleigh and authority without limitationTaylor are independent within the meaning of the NYSE listing standards currently in effect and that Messrs. Tripodo and Bonanno are independent within the meaning of10A-3 of the Exchange Act. In assessing the

independence of our directors, the board of directors considered a number of factors including, for example, with respect to these committees. Messrs. Lovoi, Loyd and Raleigh, their affiliation with Roan Holdings, with respect to Messrs. Bonanno, Lederman and Taylor, their prior affiliation with New LINN and with the York Capital funds, the Fir Tree funds and the Elliott funds, respectively, and with respect to Mr. Tripodo, his affiliation with Arch Creek Advisors LLC, which previously provided temporary consulting services to the Company in exchange for fees less than $120,000 in any given year.

Committees of the Board of Directors

We anticipate that we will have an audit committee, composedcompensation committee and nominating and corporate governance committee of our fiveboard of directors, and may have such other committees as the board of directors shall determine from time to time.

Audit Committee

We have an audit committee consisting of Messrs. Tripodo and Bonanno, with Mr. Tripodo as the Audit Committee’s Chairman and “audit committee financial expert,” as defined by the SEC. Our board of directors has affirmatively determined that each member of our audit committee meets the definition of “independent director” under the NYSE listing standards and the independence requirements ofRule 10A-3 under the Exchange Act, and that each member of our audit committee is financially literate. On April 15, 2019, Mr. Mills was appointed as the Executive Chairman and began to serve the role of the principal executive officer, in each case, on an interim basis until a successor is appointed. In connection with this appointment, Mr. Mills stepped down from the audit committee. We intend to add a third independent board member to the Audit Committee prior to November 2019.

This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, Messrs. Alcorn, Dunlap, Jacobs, McCoyincluding: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and Swoveland, uponour accounting practices. In addition, the closingaudit committee oversees our compliance programs relating to legal and regulatory requirements. We have adopted an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of this offering. the SEC and NYSE.

Compensation Committee

We do not anticipate having any other board committees, includinghave a compensation committee orconsisting of Messrs. Lovoi, Lederman and Taylor, with Mr. Taylor as the compensation committee’s Chairman. Our board has affirmatively determined that each of Messrs. Lovoi, Lederman and Taylor meets the definition of “independent director” under the NYSE listing standards and the rules of the SEC.

This committee establishes salaries, incentives and other forms of compensation for officers and other employees. The compensation committee also administers our incentive compensation and benefit plans. We have adopted a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC, the Public Company Accounting Oversight Board (“PCAOB”) and NYSE.

Nominating and Corporate Governance Committee

We have a nominating and corporate governance committee. See “Risk Factors—Risks Inherent in an Investment in LinnCo—We are a “controlled company” withincommittee consisting of Messrs. Lederman, Loyd, Raleigh and Tripodo, with Mr. Loyd as the meaningnominating and corporate governance committee’s Chairman. Our board has affirmatively determined that each of Messrs. Lederman, Loyd, Raleigh and Tripodo meets the definition of “independent director” under the NYSE listing standards and the rules of the NASDAQ’s rulesSEC.

This committee identifies, evaluates and intendrecommends qualified nominees to relyserve on exemptions from variousour board of directors, develop and oversee our internal corporate governance requirements immediately followingprocesses and maintain a management succession plan.

We have adopted a nominating and corporate governance committee charter defining the closingcommittee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. No member of our board of directors is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics, which sets forth legal and ethical standards of conduct for all our employees, as well as our directors. We also have adopted a separate code of ethics which applies to our Chief Executive Officer and Senior Financial Officers. All of these documents are available on our website,www.roanresources.com, and will be provided free of charge to any shareholder requesting a copy by writing to our Investor Relations Contact, Roan Resources, Inc., 14701 Hertz Quail Springs Pkwy, Oklahoma City, Oklahoma 73134. If any substantive amendments are made to the Code of Ethics for our Chief Executive Officer and Senior Financial Officers or if we grant any waiver, including any implicit waiver, from a provision of such code, we will disclose the nature of such amendment or waiver within four business days on our website. The information on our website is not, and shall not be deemed to be, a part of this offering.” Pursuant tofiling or incorporated into any other filings we make with the Omnibus Agreement, LINN will be responsible for any compensation paid to our officers and directors. See “Certain Relationships and Related Transactions—SEC.

Corporate Governance Guidelines

Our Relationship with Linn Energy, LLC —Omnibus Agreement.”

Officers and Employees

The board can appoint and terminate officers at any time in its sole discretion. The board can delegate power and authority to officers, employees, agents and consultants, including the power to represent us and bind usof directors has adopted corporate governance guidelines in accordance with the scopecorporate governance rules of their duties.the NYSE. The authority and function of our officersguidelines will be identical to the authority and functions of officers of a corporation organized under the DGCL, except with respect to fiduciary duties. LINN’s employees are expected to provide us with services required for our operation and administration. The costs of these services will be borne by LINN. Our initial officers will be the same individuals who serve as officers of LINN.

Capital Structure

Our present capital structure consists of two classes of shares: (1) the common shares, which are the class of shares being sold in this offering; and (2) the voting shares, of which there is currently one share outstanding, held by LINN. We are authorized to issue an unlimited number of additional voting shares and shares of the class being sold in this offering. Additional classes of shares may be created with the approval of the board, provided

Index to Financial Statements

that any such additional class must be approved by a vote of holders of a majority of our outstanding shares and by the holder(s) of our voting share(s), voting as separate classes. Our shareholders will not have preemptive or preferential rights to acquire additional shares or other securities.

Dissolution and Winding Up

We will be dissolved and wound up only: (1) upon entry of a judicial decree of dissolution of us, (2) upon the approval by the owner(s) of the voting share(s) and by the holders of a majority of the outstanding shares of the class sold in this offering, voting as separate classes, (3) if we cease to own any LINN units (whether as a result of a merger of LINN or otherwise) and the owner(s) of the voting share(s) approve such dissolution, (4) in the event of a sale or other disposition of all or substantially all of our assets other than in connection with certain non-cash mergers involving LINN or (5) if at any time we have no members, unless a member is admitted to LinnCo and LinnCo is continued without dissolution in accordance with the LLC Act. In the event that we are dissolved, our affairs will be wound up and all our remaining assets, after payments to creditors and satisfaction of other obligations, will be distributed to the holders of the outstanding shares.

If LINN or its successor is treated as a corporation for U.S. federal income tax purposes, LINN or such successor will have the right to cause us to merge with and into LINN, in which case our shareholders would receive distributions in kind of LINN units and other property we own, if any, after payments to creditors and satisfaction of other obligations.

Exculpation and Indemnification

Notwithstanding any express or implied provision of our limited liability company agreement, or any other legal duty or obligation, none of our directors or officers or the owner(s) of the voting share(s) or its officers, directors or affiliates will be liable to us, our affiliates or any other person for breach of fiduciary duty, except for acts or omissions not in good faith. Additionally, our directors will not be responsible for any misconduct or negligence on the part of an agent appointedreviewed regularly by our board of directors in good faith.the light of changing circumstances in order to continue serving our best interests and the best interests of our stockholders.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The Company was not formed until September 19, 2018, and therefore, we did not have executive officers or pay any compensation to officers or employees prior to such date. However, the operations of Roan LLC are being carried on by us following our Reorganization, and the executive officers of Roan LLC are our executive officers since our Reorganization. As such, disclosure regarding our executive officers’ compensation, including the portion prior to the Reorganization which was established and paid by Roan LLC, is relevant to our stockholders and, accordingly, is disclosed in this Compensation Discussion and Analysis (“CD&A”) and the executive compensation tables and narrative that follow.

This CD&A describes Roan LLC’s practices with regard to the compensation of our named executive officers (our “Named Executive Officers”) for the fiscal year ended December 31, 2018 (the “2018 Fiscal Year”). Our Named Executive Officers for the 2018 Fiscal Year include:

Name

Title

Tony C. Maranto

President and Chief Executive Officer (1)

David M. Edwards

Chief Financial Officer (2)

Greg T. Condray

Executive Vice President – Geoscience and Business Development

Joel L. Pettit

Executive Vice President – Operations and Marketing

Amber N. Bonney

Vice President and Chief Accounting Officer (3)

(1)

Mr. Maranto resigned as President and Chief Executive Officer on April 12, 2019.

(2)

Mr. Edwards became our Chief Financial Officer on June 18, 2018.

(3)

Ms. Bonney became our Chief Accounting Officer on February 26, 2018; however, she was serving in such capacity through a third party service provider beginning January 25, 2018.On February 9, 2019, Ms. Bonney was appointed as Vice President.

Process for Determining Compensation

Historically, the board of managers of Roan LLC was responsible for oversight of the compensation of our Named Executive Officers, with the objective of attracting talented executives. Input from Mr. Maranto regarding the material components of each Named Executive Officer’s (other than Mr. Maranto) employment arrangement was considered by the board of managers of Roan LLC in making compensation determinations with respect to Named Executive Officers other than Mr. Maranto. Following the Reorganization, the Compensation Committee did not make adjustments with respect to the compensation of our Named Executive Officers for the 2018 Fiscal Year, except as discussed below under “Elements of Compensation—Base Salaries” and the determination of 2018 bonuses discussed below under “Elements of Compensation—Annual Bonuses.”

Elements of Compensation

Base Salaries

Each Named Executive Officer’s base salary is a fixed component of compensation for performing specific job duties and functions. The base salaries of our Named Executive Officers in effect for the 2018 Fiscal Year were established in connection with the negotiation of each Named Executive Officer’s employment agreement at a level the board of managers of Roan LLC determined was necessary to obtain each Named Executive Officer’s services. In December 2018, our board implemented a cost of living increase to Ms. Bonney’s base salary. The base salary in effect as of December 31, 2018 for each Named Executive Officer is reflected in the table below:

Name

  Base Salary 

Tony C. Maranto

  $525,000 

David M. Edwards

  $375,000 

Greg T. Condray

  $400,000 

Joel L. Pettit

  $350,000 

Amber N. Bonney

  $248,400 

Annual Bonuses

Each Named Executive Officer is generally eligible to receive an annual bonus each fiscal year. For the 2018 Fiscal Year, the annual bonuses were discretionary; however, in determining such annual bonuses, the Compensation Committee reviewed various components of our operating performance during the 2018 Fiscal Year, including capital expenditures (which exceeded expectations), production (which fell below expectations) and overall capital efficiency (which also fell below expectations), as well as our stock price performance during 2018 Fiscal Year (which underperformed expectations). In light of these considerations, the Compensation Committee determined that the following annual bonuses for our Named Executive Officers were appropriate.

Name

  2018 Annual
Bonus
 

Tony C. Maranto

  $0 

David M. Edwards

  $130,000 

Greg T. Condray

  $140,000 

Joel L. Pettit

  $130,000 

Amber N. Bonney

  $155,000 

Long-Term Incentive Compensation

Performance Share Unit Awards

In connection with the commencement of Mr. Edwards’s and Ms. Bonney’s employment, Roan LLC granted PSU awards to them. The board of managers of Roan LLC determined that it was appropriate to grant these PSU awards in order to incentivize management to focus on growing the total equity value of the Company, provide an incentive for Mr. Edwards and Ms. Bonney to accept their respective offers of employment and provide a retention incentive for them to remain employed by us throughout the performance period. The PSU awards vest based on the extent to which the Company’s equity value increases over a three-year performance period commencing on January 1, 2018 and ending December 31, 2020, as set forth in the table below:

Company Equity Value

   

Percentage of Target
Performance Share Units Earned

Below

  $3,000,000,000    0  Below Threshold
  $3,000,000,000    25  
  $3,500,000,000    50  
  $4,000,000,000    75  
  $4,500,000,000    100  Target
  $5,000,000,000    125  
  $5,500,000,000    150  
  $6,000,000,000    200  Maximum

Amended and Restated Management Incentive Plan

In connection with our Reorganization, the MIP was amended, restated and renamed the Roan Resources, Inc. Amended and Restated Management Incentive Plan (the “Amended and Restated MIP”), and all outstanding PSU awards, including those held by our Named Executive Officers, were adjusted to reflect our Reorganization. Specifically, (i) the number of “Target PSUs” subject to each PSU award was multiplied by 0.05, (ii) all references to “Units” in each PSU award agreement were modified to instead refer to shares of Class A common stock such that, to the extent earned, each PSU represents the right to receive one share of Class A common stock rather than one common unit of Roan LLC, (iii) all references to Roan LLC in each PSU award agreement were modified to instead refer to the Company and (iv) all references to the MIP in each PSU award agreement were modified to instead refer to the Amended and Restated MIP.

Other Compensation Elements

Employment Agreements

As described below in “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table,” Roan LLC entered into an employment agreement in connection with the commencement of each Named Executive Officer’s employment, other than Ms. Bonney. Ms. Bonney entered into an employment agreement with the Company and Roan LLC in April 2019. See “—Fiduciary Duties”Actions Taken Following Year End—Employment Agreement with Ms. Bonney” for more information regarding Ms. Bonney’s employment agreement.

Benefit Plans

In 2018, we adopted a 401(k) retirement plan and health and welfare benefit plans in which our Named Executive Officers are eligible to participate. Under the 401(k) retirement plan, we provide for an employer match of employee contributions of up to 6% of eligible compensation and a profit sharing contribution of up to 8% of eligible compensation.

Actions Taken Following Fiscal Year End

Base Salary Adjustments

In February 2019, our board of directors determined that it was appropriate to increase the base salaries for certain of our Named Executive Officers, as set forth in the table below, to provide a further retention incentive and address certain internal equity considerations. Ms. Bonney’s base salary was increased as a result of her promotion to Vice President.

Name

  2018 Base
Salary
   2019 Base
Salary
 

Tony C. Maranto

  $525,000   $525,000 

David M. Edwards

  $375,000   $410,000 

Greg T. Condray

  $400,000   $410,000 

Joel L. Pettit

  $350,000   $380,000 

Amber N. Bonney

  $248,400   $270,000 

Employment Agreement with Ms. Bonney

On April 29, 2019, the Company and Roan LLC entered into an employment agreement with Ms. Bonney, which generally provides the same terms as the employment agreements with our other Named Executive Officers. See “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table” for a description of good faith.

Under our limited liability companythe employment agreements. The employment agreement provides Ms. Bonney with an annualized base salary of at least $270,000 and subjectan opportunity to specified limitations, we will indemnifyearn an annual bonus with a target equal to 60% of her annualized base salary. Pursuant to the fullest extent permitted by law, from and against all losses, expenses (including attorneys’ fees), judgments, fines, penalties, interest, settlement amounts, claims, damages or similar events any director or officer, or while serving as a director or officer, any person whoterms of the employment agreement, Ms. Bonney is or was serving as a director, officer, employee, partner, manager, fiduciary or trustee of any or our affiliates. However, such directors, officers and persons are only entitledeligible to indemnification if they acted in good faith and in a manner reasonably believed to be in (or not opposed to) our best interests and, with respect to any criminal proceeding or action, had no reasonable cause to believe that such conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere shall not itself create a presumption that such good faith and reasonable belief standards were not met. Additionally, we may indemnify any person who is or was an employee (other than an officer) or agent of us or LINN who is a party to a threatened, pending or completed action, suit or proceeding, to the extent permitted by law and authorized by our board of directors.

Any indemnification under our limited liability company agreement will be paid by LINN directly or indirectly on our behalf. We are authorized to purchase, or have LINN purchase on our behalf, insurance against liabilities asserted against and expenses incurred by directors, officers and personsreceive severance payments in connection with certain terminations of employment, which are described in more detail below under “Potential Payments Upon Termination or Change in Control-Bonney Employment Agreement.”

2019 Equity Awards

On April 26, 2019, the Board of Directors approved grants of equity awards to each of our activities or their activitiesNamed Executive Officers, other than Mr. Maranto. The equity awards consist of 50% time-based restricted stock units, which vest ratably over three years, and 50% performance share units, which vest in two years subject to the achievement of certain stock price hurdles.

Separation Agreement with Mr. Maranto

In connection with Mr. Maranto’s resignation, we entered into a Separation Agreement and General Release of Claims with Mr. Maranto on our behalf, regardlessApril 26, 2019 (the “Maranto Separation Agreement”). Pursuant to the Maranto Separation Agreement, Mr. Maranto will receive (a) a lump sum cash payment of whether we would have the power$262,500, (b) reimbursement for up to indemnify the person against liabilities12 months of a portion of any premiums he pays for continuation coverage under our limited liability company agreement.

group health plans pursuant to COBRA based upon the difference between the amount Mr. Maranto pays to continue such coverage and the contribution amount that similarly situated employees of the Company pay for the same or similar coverage under such group health plans and (c) a lump sum cash payment equal to six weeks of accrued but unused vacation.

Index to Financial Statements

AmendmentsOther Compensation-Related Matters

ExceptRisk Assessment

The Compensation Committee has reviewed our compensation policies as provided below, amendmentsgenerally applicable to our limited liability company agreementemployees and tobelieves that our certificatepolicies do not encourage excessive and unnecessary risk-taking, and that the level of formation can be approved in writing solely by the owner(s) of our voting share(s). Approval of a majority of our outstanding sharesrisk that they do encourage is required for any amendment which:

is determined by our board of directors, in its sole discretion,not reasonably likely to have a material adverse effect on us. Our management team regularly assesses the preferencesrisks arising from our compensation policies and practices, and they review and discuss the design features, characteristics, performance metrics and approval mechanisms of total compensation for all employees, including salaries, bonuses, and equity-based compensation awards, to determine whether any of these policies or rights of our shareholders;

reduces the time for any noticeprograms could create risks that are reasonably likely to which the holders of our shares may be entitled;

enlarges the obligations of our shareholders;

alters the circumstances under which LinnCo could be dissolved and wound up; or

changes the term of existence of LinnCo.

Certain amendments will not be considered material and may be made by our board of directors without the approval of our shareholders, including amendments:

made in order to meet the requirements of applicable securities and other laws and regulations and exchange rules;

to effect the intent of the provisions of our limited liability company agreement;

to facilitate the ability of our shareholders to obtain the benefits of, or to otherwise facilitate the consummation of, a Terminal Transaction;

that our board of directors determines in its sole discretion will not have a material adverse effect on the preferences or rights associatedus.

Accounting and Tax Considerations of Executive Compensation Decisions

The performance share unit awards granted in 2018 were accounted for in accordance with the shares;Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”), which requires us to estimate the expense of the award over the vesting period applicable to the award.

Section 162(m) of the Internal Revenue Code of 1986, as amended, generally imposes a $1 million limit on the amount of compensation paid to “covered employees” (as defined in Section 162(m)) that a public corporation may deduct for federal income tax purposes in any year. Compensation paid to certain of our executives could be subject to the $1 million per year deduction limitation imposed by Section 162(m). While we will continue to monitor our compensation programs in light of the deduction limitation imposed by Section 162(m), our Compensation Committee considers it important to retain the flexibility to design compensation programs that are in the best long-term interests of the company and our shareholders. As a result, we have not adopted a policy requiring that all compensation be fully deductible. The Compensation Committee may conclude that paying compensation at levels in excess of the limits under Section 162(m) is nevertheless in the best interests of the Company and our shareholders.

2018 Summary Compensation Table

The table below sets forth the annual compensation earned during the 2018 Fiscal Year by our Named Executive Officers:

Name and Principal Position

 Year  Salary ($)(1)  Bonus ($)(2)  Unit Awards
($)(4)
  All Other
Compensation
($)(5)
  Total ($) 

Tony C. Maranto

  2018  $525,000   —     —    $31,708  $556,708 

President and Chief Executive Officer

  2017  $90,865   —    $10,575,000   —    $10,665,865 

David M. Edwards

  2018  $180,289  $130,000  $2,565,000  $19,807  $2,895,096 

Chief Financial Officer

      

Greg T. Condray

  2018  $400,000  $140,000   —    $29,400  $569,400 

Executive Vice President – Geoscience & Business Development

  2017  $53,846  $250,000(3)  $3,102,000   —    $3,405,846 

Joel L. Pettit

  2018  $350,000  $130,000   —    $57,963  $537,963 

Executive Vice President – Operations and Marketing

  2017  $53,846   —    $2,820,000   —    $2,873,846 

Amber N. Bonney

  2018  $240,888  $155,000  $615,000  $22,815  $1,033,703 

Vice President andChief Accounting Officer

      

(1)

The amounts in this column represent only the portion of the 2018 Fiscal Year in which each Named Executive Officer was employed with Roan LLC. Mr. Edwards’s employment with Roan LLC commenced June 18, 2018; and Ms. Bonney’s employment with Roan LLC commenced January 25, 2018. Amounts in this column for the 2018 Fiscal Year for Ms. Bonney also include the amount of fees we paid for services Ms. Bonney provided to us through a third party service provider during January and February 2018 prior to the commencement of her employment with us on February 26, 2018.

(2)

The amounts in this column for 2018 represent discretionary annual bonuses paid to our Named Executive Officers in February 2019 for services provided during the 2018 Fiscal Year.

(3)

In connection with his appointment as Executive Vice President – Geoscience and Business Development, Mr. Condray received aone-time signing bonus of $250,000.

(4)

The amounts in this column represent the aggregate grant date fair value of the PSU awards granted to each of our Named Executive Officers, calculated in accordance with FASB ASC Topic 718, disregarding estimated forfeitures. For additional information regarding the assumptions underlying this calculation, please see Note 11 to the historical financial statements, entitled “Equity Compensation,” which is included in this prospectus. Please see the section of the CD&A above entitled “Performance Share Unit Awards” and the “Grants of Plan-Based Awards Table” below for additional information regarding these awards.

(5)

Amounts in this column reflect our employer match of 401(k) plan contributions in the 2018 Fiscal Year for each Named Executive Officer. Additionally, for Mr. Pettit, the amount in this column also reflects $34,420 of reimbursements for relocation expenses provided to him in accordance with our relocation reimbursement policy.

Grants of Plan-Based Awards

The table below includes information about PSU awards granted to our Named Executive Officers during the 2018 Fiscal Year, as adjusted to reflect the Reorganization.

   Grant
Date
   Estimated Future Payouts Under Equity
Incentive Plan Awards (1)
   Grant Date Fair
Value of Unit
Awards ($)(2)
 

Name

  Threshold
(#)
   Target
(#)
   Maximum
(#)
 

Tony C. Maranto

   —      —      —      —      —   

David M. Edwards

   6/18/2018    18,750    75,000    150,000   $2,565,000 

Greg T. Condray

   —      —      —      —      —   

Joel L. Pettit

   —      —      —      —      —   

Amber N. Bonney

   2/26/2018    3,750    15,000    30,000   $615,000 

(1)

Amounts in these columns represent the number of PSU awards granted in 2018 that would vest upon the achievement of a threshold, target, or maximum level of performance, as adjusted to reflect the Reorganization. The actual number of PSU awards that will vest will not be determinable until the close of the performance period on December 31, 2020 and will depend on the Company’s equity value at such time.

(2)

Amounts in this column represent the grant date fair value of PSU awards granted to our Named Executive Officers in 2018 computed in accordance with FASB ASC 718. For additional information regarding the assumptions underlying this calculation, please see Note 11 to the historical financial statements, entitled “Equity Compensation,” which is included in this prospectus. Please see the section of the CD&A above entitled “Long-Term Incentive Compensation” for additional information regarding these awards.

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

As of December 31, 2018, Roan LLC had entered into employment agreements with each of our Named Executive Officers other than Ms. Bonney. Each employment agreement has an initial three-year term that will automatically renew for successiveone-year periods until terminated in writing by either party at least 60 days prior to the renewal date. The employment agreements provide for annualized base salaries of at least $525,000 for Mr. Maranto, $375,000 for Mr. Edwards; $400,000 for Mr. Condray; and $350,000 for Mr. Pettit. Additionally, the employment agreements provide each Named Executive Officer with the opportunity to earn an annual bonus for each complete calendar year such Named Executive Officer is employed thereunder, and establishes targets as a percentage of each Named Executive Officer’s annualized base salary of 125% for Mr. Maranto, 100% for Messrs. Edwards and Condray, and 75% for Mr. Pettit. Each Named Executive Officer is also eligible to receive annual equity grants and participate in all benefits generally available to similarly situated employees. Additionally, each employment agreement contains certain restrictive covenants applicable to each Named Executive Officer. Pursuant to the terms of the employment agreements, each Named Executive Officer is eligible to severance payments in connection with certain terminations of employment, which are described in more detail below on the section titled “Potential Payments Upon Termination or Change in Control.”

Outstanding Equity Awards at FiscalYear-End

The following table reflects information regarding outstanding PSU awards held by our Named Executive Officers as of December 31, 2018.

Name

  Equity Incentive Plan
Awards: Number of
Unearned Shares, Units
or Other Rights That
Have Not Vested (#)(1)(2)
   Equity Incentive Plan
Awards: Market or Payout
Value of Unearned Shares,
Units or Other Rights That
Have Not Vested ($)(3)
 

Tony C. Maranto(4)

   93,750   $785,625 

David M. Edwards

   18,750   $157,125 

Greg T. Condray

   27,500   $230,450 

Joel L. Pettit

   25,000   $209,500 

Amber N. Bonney

   3,750   $31,425 

(1)

Each Named Executive Officer’s outstanding PSU awards will become earned over the performance period ending December 31, 2020 depending on the level of achievement of the applicable performance conditions and so long as such Named Executive Officer remains continuously employed with Roan LLC through such date. The number of units reported in this column assumes that the equity value of Roan LLC for the performance period is achieved at the threshold level, which may not be representative of the actual payouts that will occur upon the settlement of the PSU awards, as such actual payouts may be significantly more or less.

(2)

To the extent earned, each performance share unit subject to a PSU award represents the right to receive one share of Class A common stock upon vesting. As described above, in connection with our Reorganization, the PSU awards have been adjusted to reflect our Reorganization, including to convert the Roan LLC units subject to the outstanding PSU awards to shares of Class A common stock.

(3)

Amounts in this column reflect the market value of the shares of Class A common stock subject to the PSU awards, calculated by multiplying the number of shares reported by $8.38, the closing price of our Class A common shares on December 31, 2018.

(4)

Upon his resignation, Mr. Maranto forfeited his outstanding PSUs.

Option Exercises and Stock Vested

No equity awards held by our Named Executive Officers vested during the 2018 Fiscal Year. We have not granted options pursuant to the Amended and Restated MIP since its adoption.

Pension Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan.

Nonqualified Deferred Compensation

We have not maintained, and do not currently maintain, a nonqualified deferred compensation plan.

Potential Payments Upon Termination or Change in Control

Employment Agreements

As described above in the section entitled “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table,” as of December 31, 2018, we had entered into employment agreements with each of our Named Executive Officers, other than Ms. Bonney, that provide for severance payments in certain circumstances. Upon a termination of Messrs. Maranto’s, Edwards’s, Condray’s or Pettit’s employment by us without “cause” or upon such Named Executive Officer’s resignation for “good reason,” such Named Executive Officer is eligible for 24 months’ worth of base salary payable in 12 equal installments, subject to such Named Executive Officer’s execution of a release and continued compliance with the restrictive covenants set forth in such Named Executive Officer’s employment agreement. Additionally, each employment agreement provides that annual equity-based awards (excluding the PSU awards described below) will fully accelerate upon the death of the Named Executive Officer (subject to any applicable performance requirements); however, as of December 31, 2018, no such annual equity-based awards are currently outstanding.

Under each employment agreement:

“cause” generally means (a) a material breach by such Named Executive Officer of the employment agreement or any other agreement with Roan LLC, (b) the commission of gross negligence, willful misconduct, breach of fiduciary duty, fraud, theft or embezzlement by such Named Executive Officer, (c) the commission by, conviction or indictment of or plea of nolo contendere by such Named Executive Officer to any felony (or state law equivalent) or any crime involving moral turpitude or (d) such Named Executive Officer’s willful failure or refusal to perform his obligations or to follow lawful directives from the board of directors; and

“good reason” generally means any of the following without such Named Executive Officer’s consent: (a) a material diminution in base salary, titles or duties, (b) a material breach by Roan LLC of the employment agreement or any other agreement with such Named Executive Officer or (c) a geographic relocation of such Named Executive Officer’s principal place of employment by more than 50 miles.

Performance Share Unit Awards

Under the award agreement governing the terms of each Named Executive Officer’s PSU awards, if a Named Executive Officer’s employment with us terminates as a result of (a) a termination by us without “cause,”

(b) such Named Executive Officer��s resignation for “good reason,” or (c) such Named Executive Officer’s death or “disability,” then apro-rata portion of the PSUs shall become vested based on the number of days which have elapsed from the commencement of the performance period through the date of termination and the achievement of the performance goals for the entire performance. If a termination described in the preceding sentence occurs within theone-year period following a “change in control,” then the performance period shall be deemed to have ended on the date of such change in control, and the PSUs will be settled based on the achievement of the performance goals through the date of such change in control.

As used in the PSU awards, “cause” and “good reason” have the meanings described above under “Employment Agreements.” As used in the PSU awards, “disability” generally means the inability of our Named Executive Officer to perform the essential functions of his or her position due to physical or mental impairment or other incapacity that continues for more than 120 consecutive days or more than 180 days in any12-month period. As used in the PSU awards prior to the Reorganization, “change in control” generally meant the occurrence of any of the following events:

a “change in the ownership of the company,” which would occur on the date that any one person, or more than one person acting as a group, acquires ownership of securities in us that, together with securities held by such person or group, constitutes more than 50% of the total fair market value or total voting power of our securities;

 

a change“change in our name, the locationeffective control of the company,” which would occur on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the12-month period ending on the date of the most recent acquisition) ownership of our principal placesecurities possessing 30% or more of business,the total voting power of our registered agentsecurities; or its registered office;

 

a “change in the admission, substitution, withdrawalownership of a substantial portion of our assets,” which would occur on the date that any one person, or removalmore than one person acting as a group, acquires (or has acquired during the12-month period ending on the date of members in accordance with our limited liability company agreement;

the mergermost recent acquisition) assets that have a total gross fair market value equal to or more than 40% of us into, or the conveyancetotal gross fair market value of all of our assets immediately prior to such acquisition.

The Reorganization did not constitute a newly-formed entity if“change in control” for purposes of the sole purposePSU awards.

Following the Reorganization, “change in control” generally means the occurrence of that mergerany of the following events:

acquisition by any person or conveyance is to effect a mere change ingroup of beneficial ownership of 50% or more of the legal form into another limited liability entity that is taxed as a corporation for U.S. federal income tax purposes;outstanding shares of Class A common stock or the combined voting power of the outstanding voting securities of Roan Inc.;

 

the incumbent directors cease to constitute at least a change thatmajority of the board of directors determines to be necessary or appropriate for us to qualify or continue its qualification as an entity in which the members have limited liability under the laws of any state or to ensure that we will be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes;directors;

 

an amendment that is necessary, inconsummation of a business combination unless following such business combination (a) the opinionoutstanding Class A common stock or voting securities of our counsel,Roan Inc. immediately prior to prevent us, memberssuch business combination represent more than 50% of our board,the equity interests or our officers, agentsvoting power of the entity resulting from the business combination, (b) no person or trusteesgroup beneficially owns 50% or more of the outstanding equity interests or voting power of the entity resulting from in any manner being subjectedthe business combination unless such ownership results solely from ownership prior to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

an amendment that our board of directors determines to be necessary or appropriate for the authorizationbusiness combination, and the issuance of additional common shares or voting shares;

any amendment expressly permitted in our limited liability company agreement to be made by the board of directors acting alone;

an amendment effected, necessitated or contemplated by(c) a merger agreement that has been approved under the terms of our limited liability company agreement;

Index to Financial Statements

a merger, conversion or conveyance effected in accordance with our limited liability company agreement; and

any other amendments substantially similar to any of the matters described in the clauses above.

The provision of our limited liability company agreement preventing the amendments having the effects described above can be amended upon the approval of the holders of a majority of our outstanding shares and by the holder(s) of our voting share(s), voting as separate classes. For more information regarding the voting rights of our shareholders and other amendments we may make, please read “—Voting Rights.”

Meetings; Approvals

All notices of meetings of shareholders shall be sent or otherwise given in accordance with our limited liability company agreement not less than 10 nor more than 60 days before the date of the meeting. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted (no business other than that specified in the notice may be transacted) or (ii) in the case of the annual meeting, those matters which the board of directors, at the time of giving the notice, intends to present for action by the shareholders (but any proper matter may be presented at the meeting for such action). Any previously scheduled meeting of the shareholders may be postponed, and any special meeting of the shareholders may be canceled, by resolution of the board of directors upon public notice givenof the entity resulting from such business combination were incumbent directors prior to the date previously scheduled for such meetingbusiness combination; or

complete liquidation or dissolution of shareholders.Roan Inc.

Any action required or permittedThe foregoing description is not intended to be takena comprehensive summary of the employment agreements or award agreements governing the PSU awards and is qualified in its entirety by reference to such agreements, which are filed as exhibits to the registration statement of which this prospectus forms a part.

The following table sets forth the payments and benefits that would be received by each Named Executive Officer in the event a termination of employment or a change in control of Roan Inc. had occurred on December 31, 2018, over and above any payments or benefits the Named Executive Officer otherwise would already have been entitled to or vested in on such date under any employment agreement or other plan of Roan Inc.

Executive

  Termination of
Employment by
Roan LLC
Without
Cause or by
Executive for
Good Reason ($)
  Termination of
Employment due
to Death or
Disability ($)
  Termination of
Employment by
Roan LLC
Without Cause for
by Executive for
Good Reason
following Change
in Control ($)(2)
  Termination of
Employment by
Roan LLC for
Cause, by Notice of
Non-Renewal, or by
Executive Without
Good Reason ($)
 

Tony C. Maranto

     

Cash Severance

  $1,050,000               —    $1,050,000               —   

Accelerated Equity

   —  (1)   —  (1)   —  (1)   —   

Total

  $1,050,000   —    $1,050,000   —   

David M. Edwards

     

Cash Severance

  $750,000   —    $750,000   —   

Accelerated Equity

   —  (1)   —  (1)   —  (1)   —   

Total

  $750,000   —    $750,000   —   

Greg T. Condray

     

Cash Severance

  $800,000   —    $800,000   —   

Accelerated Equity

   —  (1)   —  (1)   —  (1)   —   

Total

  $800,000   —    $800,000   —   

Joel L. Pettit

     

Cash Severance

  $700,000   —    $700,000   —   

Accelerated Equity

   —  (1)   —  (1)   —  (1)   —   

Total

  $700,000   —    $700,000   —   

Amber N. Bonney

     

Cash Severance

   —     —     —     —   

Accelerated Equity

   —  (1)   —  (1)   —  (1)   —   

Total

   —     —     —     —   

(1)

Because the value of the PSU awards received under the applicable acceleration scenarios described under “Performance Share Unit Awards” above is based on actual performance through the date specified under “Performance Share Unit Awards” above, no value is reported for the PSU awards, as performance through the date used for purposes of these calculations was below threshold.

(2)

A termination in connection with a change in control must occur within 12 months of the change in control.

Bonney Employment Agreement

On April 29, 2019, we entered into an employment agreement with Ms. Bonney as described above in “Actions Taken Following Fiscal Year End—Employment Agreement with Ms. Bonney.” The employment agreement includes the same terms and definitions regarding any severance payments as the employment agreements with our shareholdersother Named Executive Officers and as described above in “—Employment Agreements.” The following table sets forth the payments and benefits that would have been received by Ms. Bonney in the event of a termination of employment or a change in control of Roan Inc. on December 31, 2018, assuming that the employment agreement was in effect at such time.

Executive

  Termination of
Employment by
Roan LLC
Without
Cause or by
Executive for
Good Reason ($)
  Termination of
Employment due
to Death or
Disability ($)
  Termination of
Employment by
Roan LLC
Without Cause or
by Executive for
Good Reason
following Change
in Control ($)(2)
  Termination of
Employment by
Roan LLC for
Cause, by Notice of
Non-Renewal, or by
Executive Without
Good Reason ($)
 

Amber N. Bonney

     

Cash Severance

  $540,000  $—    $540,000  $—   

Accelerated Equity

  $—  (1)  $—  (1)  $—  (1)  $—   

Total

  $540,000  $—    $540,000  $—   

(1)

Because the value of the PSU awards received under the applicable acceleration scenarios described under “Performance Share Unit Awards” above is based on actual performance through the date specified under “Performance Share Unit Awards” above, no value is reported for the PSU awards, as performance through the date used for purposes of these calculations was below threshold.

(2)

A termination in connection with a change in control must occur within 12 months of the change in control.

Maranto Separation Agreement

In connection with Mr. Maranto’s resignation, we entered into the Maranto Separation Agreement as described above in “Actions Taken Following Fiscal Year End—Separation Agreement with Mr. Maranto.” Pursuant to the Maranto Separation Agreement, Mr. Maranto will receive (a) a lump sum cash payment of $262,500, (b) reimbursement for up to 12 months of a portion of any premiums he pays for continuation coverage under our group health plans pursuant to COBRA based upon the difference between the amount Mr. Maranto pays to continue such coverage and the contribution amount that similarly situated employees of the Company pay for the same or similar coverage under such group health plans and (c) a lump sum cash payment equal to six weeks of accrued but unused vacation.

CEO Pay Ratio

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) ofRegulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Tony Maranto, our Chief Executive Officer (our “CEO”).

For 2018, our last completed fiscal year:

The median of the annual total compensation of all employees of our company (other than actions by the owner(s)CEO) was $116,400; and

The annual total compensation of our voting share(s), which may be taken by written consent) must be taken at a duly calledCEO, as reported in the Summary Compensation Table included elsewhere within this prospectus, was $556,708.

Based on this information, for 2018 the ratio of the annual or special meeting of shareholders and may not be taken by any consent in writing by such shareholders.

Meetingstotal compensation of our shareholders may onlyCEO to the median of the annual total compensation of all employees was reasonably estimated to be called by a majority5 to 1.

To identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our boardmedian employee and our CEO, we took the following steps:

We determined that, as of directorsDecember 31, 2018, our employee population consisted of approximately 179 full-time individuals with all of these individuals located in the United States (as reported in Item 1, Business, in ourForm 10-K filed with the SEC on April 1, 2019).

We used a consistently applied compensation measure to identify our median employee of comparing the amount of salary or wages by the owner(s)annualizing all new hires to reflect a true calendar year of earnings. We identified our median employee by consistently applying this compensation measure to all of our voting share(s). The ownersemployees included in our analysis. Since all of our employees, including our CEO, are located in the United States, we did not make any cost of living adjustments in identifying the median employee.

After we identified our median employee, we combined all of the classelements of shares being sold in this offering do not havesuch employee’s annualized compensation for the right to call a meeting of the shareholders. Shareholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding shares of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the shareholders requires approval by holders of a greater percentage of the shares, in which case the quorum shall be the greater percentage.

The act of a majority of a quorum at a meeting constitutes the act of the shareholders, except with respect to any proposed action which we have agreed not to take without the approval of a majority of all outstanding shares of the class sold in this offering. See “—Voting Rights.”

Shares held in nominee or street name accounts will be voted by the broker or other nominee2018 year in accordance with the instructionrequirements of Item 402(c)(2)(x) ofRegulation S-K, resulting in annual total compensation of $116,400. The difference between such employee’s salary, wages and overtime pay and the employee’s annual total compensation represents the estimated annualized 401(k) contributions in the amount of $13,417 that we estimated would have been made on the employee’s behalf to our 401(k) plan for the 2018 year.

With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2018 Summary Compensation Table included in this prospectus.

Director Compensation

Prior to the Reorganization, members of the beneficial owner unlessboard of managers of Roan LLC did not receive any compensation for their services as directors. In connection with the arrangement betweenReorganization, we adopted anon-employee director compensation policy which provides for payment of the beneficial ownerfollowing annual retainers to members of our board who are not officers, employees, paid consultants or advisors of (i) us or our subsidiaries or (ii) investment funds affiliated with or managed by JVL Advisors, LLC, Elliott Management Corporation, Fir Tree Capital Management LP or York Capital Management, L.P.:

$80,000 annual base retainer;

$25,000 supplemental annual retainer for the Lead Independent Director;

$20,000 supplemental annual retainer for the chair of the Audit Committee; and its nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders

$10,000 supplemental annual retainer for the members of shares under our limited liability company agreement will be deliveredthe Audit Committee and Nominating & Governance Committee.

Pursuant to the record holder by uspolicy, ournon-employee directors also receive an annual equity award with a value on the date of grant equal to $100,000 based on the closing price of our Class A common stock on the date of grant, rounded to the nearest whole share, and as such, we granted restricted stock unit (“RSU”) awards on November 5, 2018 to each of Anthony Tripodo and Joseph A. Mills. Additionally, each director is reimbursed for travel and miscellaneous expenses to attend meetings and activities of our board or byits committees.

The table below sets forth the transfer agent.

compensation paid to ournon-employee directors during the 2018 Fiscal Year.

Index to Financial Statements

Name

  Fees Earned
or Paid in
Cash ($)
   Stock Awards
($)(1)
   Total ($) 

Anthony Tripodo

  $36,318   $100,005   $136,323 

Joseph A. Mills

  $15,489   $100,005   $115,494 

Voting Rights

(1)

The amounts in this column represent the aggregate grant date fair value of the RSUs granted to Messrs. Tripodo and Mills, calculated in accordance with FASB ASC Topic 718, disregarding estimated forfeitures.

Equity Compensation Plan Information

The following matters require the shareholder vote specified below:table sets forth information about shares of Class A common stock that may be issued under equity compensation plans as of December 31, 2018.

   (a)   (b)   (c) 
   Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights (1)
   Weighted-average
exercise price of
outstanding options,
warrants and rights (2)
   Number of securities
remaining available for
future issuance under equity
compensation plans
(excluding securities reflected
in column (a)) (3)
 

Equity compensation plans approved by security holders

   —      —      —   

Equity compensation plans not approved by security holders

   2,329,300    —      12,924,654 

Total

   2,329,300    —      12,924,654 

 

(1)

ElectionThis column reflects the maximum number of Class A common shares subject to PSU awards and the number of Class A common shares subject to RSU awards granted under the Amended and Restated MIP outstanding and unvested as of December 31, 2018. Because the number of units to be issued upon settlement of outstanding PSU awards is subject to performance conditions, the number of units actually issued may be substantially less than the number reflected in this column. No options or warrants have been granted under the Amended and Restated MIP.

(2)

No options or warrants have been granted under the Amended and Restated MIP, and the RSU and PSU awards reflected in column (a) are not reflected in this column, as they do not have an exercise price.

(3)

This column reflects the total number of Class A common shares remaining available for issuance under the Amended and Restated MIP as of December 31, 2018.

PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth the beneficial ownership of our Class A common stock as of May 24, 2019:

the selling stockholders;

each person known to us to beneficially own more than 5% of our outstanding Class A common stock;

each of our directors;

our Named Executive Officers; and

all of our directors and executive officers as a group.

For further information regarding material transactions between us and the selling stockholders, see “Certain Relationships and Related Party Transactions.”

All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, directors or executive officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o Roan Resources, Inc., 14701 Hertz Quail Springs Pkwy, Oklahoma City, Oklahoma 73134. The following table is based on 152,539,532 shares of Class A common stock outstanding as of the Effective Date.

Name of Beneficial Owner

 Shares Beneficially
Owned(1)
  Shares to be Sold
Pursuant to this
Prospectus
  Shares
Beneficially
Owned After
Offering
 
 Number   %  Number   %  Number   % 

Selling Stockholders and 5% Stockholders:

         

Roan Holdings(2)

  76,269,766    50.0  76,269,766    50.0  —      —   

Elliott funds (3)

  15,794,132    10.4  15,794,132    10.4  —      —   

Fir Tree funds(4)

  14,712,070    9.6  14,712,070    9.6  —      —   

York Capital funds(5)

  9,028,373    5.9  9,028,373    5.9  —      —   

Directors and Named Executive Officers:

         

Tony C. Maranto

  20,000    *   —      —     20,000    * 

Joel L. Pettit

  —      —     —      —     —      —   

Greg T. Condray

  —      —     —      —     —      —   

Matthew Bonanno

  —      —     —      —     —      —   

Evan Lederman

  —      —     —      —     —      —   

John V. Lovoi(2)(6)

  77,604,936    50.9  77,604,936    50.9  —      —   

Paul B. Loyd, Jr.(2)

  76,269,766    50.0  76,269,766    50.0  —      —   

Michael P. Raleigh(2)

  76,269,766    50.0  76,269,766    50.0  —      —   

Andrew Taylor

  —      —     —      —     —      —   

Anthony Tripodo(7)

  —      —     —      —     —      —   

Joseph A. Mills

  —      —     —      —     —      —   

David M. Edwards

  —      —     —      —     —      —   

Amber N. Bonney

  —      —     —      —     —      —   

Directors and Executive Officers as a Group (13 Persons)

  77,604,936    50.9  77,604,936    50.9  —      —   

*

Less than 1%.

(1)

The amounts and percentages of Class A common stock beneficially owned are reported on the bases of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so

acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of Class A common stock, except to the extent this power may be shared with a spouse.
(2)

JVL Advisors, LLC (“JVL”), indirectly through its investment management arrangements with Asklepios Energy Fund, LP, Hephaestus Energy Fund, LP, Luxiver WI, LP, LVPU, LP, Midenergy Partners II, LP, Navitas Fund, LP, Blackbird 1846 Energy Fund, L.P., Children’s Energy Fund, LP, SPQR Energy, LP and Panakeia Energy Fund, LP (collectively, the “JVL Funds”), beneficially owns an approximate 73.61% interest in Roan Holdings and has the contractual right to nominate a majority of the members of the board of
directors

The shares that are being sold in this offering are not entitled to vote to elect our managers of Roan Holdings, which board of directors.managers exercises voting and dispositive power over all securities held by Roan Holdings. The board of managers of Roan Holdings consists of four managers, of which JVL has nominated three, Paul B. Loyd, Jr., Michael P. Raleigh and Kelly Loyd. JVL may be deemed to beneficially own all of the reported securities held by Roan Holdings. Each of the JVL Funds is controlled indirectly by John V. Lovoi. Mr. Lovoi is the sole member of, and exercises investment management control over, JVL. Messrs. Lovoi, Paul Loyd, Raleigh, Kelly Loyd, JVL and the JVL Funds may be deemed to share dispositive power over the securities held by Roan Holdings; thus, they may also be deemed to be the beneficial owners of these securities. Each of Messrs. Lovoi, Paul Loyd, Raleigh, Kelly Loyd, JVL and the JVL Funds disclaims beneficial ownership of the reported securities in excess of such entity’s or person’s respective pecuniary interest therein. The address for JVL, the JVL Funds and Messrs. Lovoi, Paul Loyd, Raleigh and Kelly Loyd is 10000 Memorial Dr., Suite 550, Houston, Texas 77024.

(3)

Consists of (i) 26,513 shares owned by Elliott Associates, L.P. (“Elliott Associates”), (ii) 5,027,660 shares owned by The Liverpool Limited Partnership (“Liverpool”) and (iii) 10,739,959 shares owned by Spraberry Investments Inc. (“Spraberry,” and collectively with Elliott Associates and Liverpool, the “Elliott funds”). The sole limited partner of Liverpool is Elliott Associates. Spraberry is an indirect subsidiary of Elliott International, L.P. (“Elliott LP”). Elliott International Capital Advisors Inc. is the investment manager of Elliott LP (“Elliott IM”) and is regulated by the SEC as an investment advisor. Elliott IM has voting and investment power with respect to the shares held by Spraberry and may be deemed to be the beneficial owner thereof. Each of Elliott Advisors GP LLC, Elliott Capital Advisors, L.P. and Elliott Special GP, LLC, is a general partner of Elliott Associates and is regulated by the SEC as an investment advisor. Each of Elliott Advisors GP LLC, Elliott Capital Advisors, L.P. and Elliott Special GP, LLC has voting and investment power with respect to the shares held by Elliott Associates and may be deemed to be the beneficial owner thereof. There is no single beneficial limited partner of Elliott Associates holding limited partnership interests equal to 10% or more of its total capital. Andrew Taylor, a member of the investment team of Elliott Management Corporation, an affiliate of the Elliott funds, serves on the board of directors of the Company. The address of each of the foregoing entities and Mr. Taylor is c/o Elliott Management Corporation, 40 West 57th Street, New York, New York 10019.

(4)

Consists of (i) 548,558 shares owned by Fir Tree Capital Opportunity Master Fund III, L.P., (ii) 1,785,444 shares owned by Fir Tree Capital Opportunity Master Fund, L.P., (iii) 9,968,920 shares owned by Fir Tree E&P Holdings VI, LLC, (iv) 1,150,589 shares owned by FT SOF IV Holdings, LLC, (v) 1,217,275 shares owned by FT SOF V Holdings, LLC and (vi) 41,284 shares owned by FT COF(E) Holdings, LLC (collectively, the “Fir Tree funds”). Fir Tree Capital Management LP (“FTCM”) (f/k/a Fir Tree Inc.) is the investment manager for the Fir Tree funds. Jeffrey Tannenbaum, David Sultan and Clinton Biondo control FTCM. Each of FTCM, Messrs. Tannenbaum, Sultan and Biondo has voting and investment power with respect to the shares of Class A common stock owned by the Fir Tree funds and may be deemed to be the beneficial owner of such shares. Evan S. Lederman, a partner of FTCM, serves on the board of directors of the Company. Mr. Lederman does not have voting and investment power with respect to the shares of Class A common stock owned by the Fir Tree funds in his capacity as a partner of FTCM. The address of each of the foregoing entities and Messrs. Tannenbaum, Sultan, Biondo and Lederman is c/o Fir Tree Capital Management LP, 55 West 46th Street, 29th Floor, New York, New York 10036.

(5)

Consists of (i) 1,329,972 shares owned by York Capital Management, L.P., (ii) 3,088,432 shares owned by York Credit Opportunities Investments Master Fund, L.P., (iii) 2,424,480 shares owned by York Credit Opportunities Fund, L.P., (iv) 1,850,097 shares owned by York Multi-Strategy Master Fund, L.P., (v) 135,392 shares owned by Exuma Capital, L.P., and (vi) 200,000 shares owned by York Select Strategy Master Fund, L.P. (collectively, the “York Capital funds”). York Capital Management Global Advisors, LLC (“YCMGA”) is the senior managing member of the general partner of each of the York Capital funds. James G. Dinan is the chairman of, and controls, YCMGA. Each of YCMGA and Mr. Dinan has voting and investment power with respect to the shares owned by each of the York Capital funds and may be deemed to be beneficial owners thereof. Each of YCMGA and Mr. Dinan disclaim beneficial ownership of such shares except to the extent of their pecuniary interests therein. Matthew W. Bonanno, a partner of YCMGA, serves on the board of directors of the Company. The address of the York Capital funds, Mr. Dinan and Mr. Bonanno is 767 Fifth Avenue, 17th Floor, New York, New York 10153.

(6)

Consists of (i) 76,269,766 shares owned by Roan Holdings and (ii) 1,335,170 shares owned by various entities (the “Lovoi Entities”) controlled indirectly by Mr. Lovoi through JVL. Mr. Lovoi is the sole member of, and exercises investment management control over, JVL. Through JVL, Mr. Lovoi exercises voting and dispositive power over all securities held by the Lovoi Entities and may be deemed to be the beneficial owner thereof. Each of Mr. Lovoi, JVL and the Lovoi Entities disclaims beneficial ownership of the reported securities in excess of such entity’s or person’s respective pecuniary interest therein. Please see footnote (2) for additional information regarding the shares owned by Roan Holdings. The address for Mr. Lovoi, JVL and the Lovoi Entities is 10000 Memorial Dr., Suite 550, Houston, Texas 77024.

(7)

Pursuant to the Stockholders Agreement, Mr. Tripodo was designated to the board of directors by Roan Holdings.

REORGANIZATION

We were incorporated under the laws of the State of Delaware in September 2018, for the purpose of facilitating a reorganization and to become a holding company of Roan LLC. Our only assets are equity interests in our subsidiaries. Prior to the reorganization, we had not engaged in any business or other activities except in connection with our formation and we had no previous operations, assets or liabilities.

Roan LLC, our predecessor, was formed as a Delaware limited liability company in May 2017 as joint venture between Old Linn and Citizen and began operations in August 2017, upon the close of the Contribution. Following these transactions, Citizen’s equity interest in Roan LLC was held through its wholly owned subsidiary, Roan Holdings).

In the third quarter of 2018, Old Linn and certain of its subsidiaries undertook an internal reorganization, pursuant to which:

(i)

on July 25, 2018, Old Linn merged with and into Linn Merger Sub #1, LLC (“Riviera Merger Sub”), a wholly owned subsidiary of New Linn, with Riviera Merger Sub surviving such merger, and all outstanding shares of Class A common stock of Old Linn were automatically converted into shares of Class A common stock of New Linn on aone-for-one basis;

 

 The sole voting share that is entitled(ii)

on July 25, 2018, New Linn caused certain of its subsidiaries to voteeffect a distribution of its indirect 50% equity interest in Roan LLC to elect our board of directors is ownedbe held directly by LINN.

New Linn;

Issuance of additional shares

No approval right.

Creation of additional classes of shares

Majority of outstanding shares and a majority of our voting share(s), voting as separate classes.

Amendment, alteration, repeal or waiver of any
provision of our limited liability company
agreement

Majority of outstanding shares and a majority of our voting share(s), voting as separate classes, for certain amendments as described in “—Amendments.”

 

 Certain amendments will not be considered material and may be made by our board of directors without the approval of our shareholders, as described in “—Amendments.”(iii)

Amendment, alteration, repeal or waiver of any
provisionon August 7, 2018, New Linn contributed to its wholly owned subsidiary, Riviera, all of the Omnibus Agreement

Majority of outstanding shares and a majority of our voting share(s), voting as separate classes, if such amendment materially adversely affects the preferences or rights of our shareholders (as determinedmembership interests in the sole discretion of our board of directors).Riviera Merger Sub; and

 

 Certain amendments(iv)

on August 7, 2018, New Linn completed thespin-off of Riviera by distributing to the Omnibus Agreement will not be considered materialLegacy Linn Stockholders all of the issued and may be made by our boardoutstanding common stock of directors without the approval of our shareholders, including amendments:Riviera on a pro rata basis.

to effect the intent of the provisions of the Omnibus Agreement;

to facilitate the ability of our shareholders to obtain the benefits of, or otherwise facilitate the consummation of, a Terminal Transaction;

to reflect any change in circumstances as a result of certain non-cash mergers involving LINN; or

that our board of directors determines in its sole discretion will not have a material adverse effect on the preferences or rights associated with the shares.

IndexThe above transactions are collectively referred to Financial Statements

Merger of LinnCo or the sale of all or substantially all of its assets

Majority of outstanding shares and a majority of our voting share(s), voting as separate classes.

Dissolution of LinnCo (other than in connection with a Terminal Transaction)

Majority of outstanding shares and a majority of our voting share(s), voting as separate classes.

LINN will not be prohibited from exercising any voting rights with respect to any shares it may own.

Fiduciary Duties

Our limited liability company agreement has modified, waived and limited fiduciary duties of our directors and officers that would otherwise apply at law or in equity and replaced such duties with a contractual duty requiring our directors and officers to act in good faith. For purposes of our limited liability company agreement, a person shall be deemed to have acted in good faith if the action or omission of action was taken with the belief that it was in, or not opposed to, the best interests of LinnCo. In addition, any action or omission of action shall be deemed to be in, or not opposed to, the best interests of LinnCo and our shareholders if such action or omission of action would be in, or not opposed to, the best interest of LINN and all its unitholders, taken together.

In taking (or refraining from taking) any action or making any recommendation to our shareholders, our directors, in determining whether such action or recommendation is in the best interest of LinnCo and our shareholders, will be permitted, but not required, to take into account the totality of the relationship between LINN and LinnCo. Accordingly, any actions taken by our board will be deemed to be in good faith and in or not opposed to the best interest of LinnCo and our shareholders if such actions would be in the best interest of LINN and all of its unitholders, taken together. In addition, when acting in their individual capacities or as officers or directors of LINN or any other entity, our directors will not be obligated to take into account the interests of LinnCo or our shareholders when taking (or refraining from taking) any action or making any recommendation.

Our limited liability company agreement permits affiliates of our directors to engage in other business interests or activities in preference to or to the exclusion of us and to engage in business interests that directly compete with us, provided that the affiliate does not engage in such competing businesses as“Riviera Separation.” As a result of the Riviera Separation, Riviera held, directly or using confidential information provided by or on behalf of us to such director. Additionally, our directors do not have any contractual obligation or express or implied legal duty to present business opportunities to us that become available to their affiliates, and neither we nor any of our shareholders have any rights in any business ventures of a director, and the pursuit of any such ventures, even if in competition with us, are not a breach of any duty of such director otherwise existing at law, in equity or otherwise.

Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney

By purchasing one of our shares, you will be admitted as a shareholder of our company and will be deemed to have agreed to be bound by the terms of our limited liability company agreement. Under that agreement, each shareholder and each person who acquires a share from a shareholder grants to our board of directors (and, if appointed, a liquidator) a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our board of directors the authority to make certain amendments to, and to make consents and waivers under and in accordance with, our limited liability company agreement. Such power of attorney shall be irrevocable and deemed coupled with an interest and shall survive a shareholder’s death, disability, dissolution, bankruptcy or termination.

Index to Financial Statements

Covenants

Our limited liability company agreement provides that our activities will be limited to owning LINN units and further includes covenants that prohibit us from:

borrowing money or issuing debt;

selling, pledging or otherwise transferring any LINN units;

issuing options, warrants or other securities entitling the holder to purchase our shares (other than in connection with employee benefit plans);

liquidating, merging or recapitalizing;

revoking or changing our election to be treated as a corporation for U.S. federal income tax purposes; or

using the proceeds from sales of our shares other than to purchase LINN units.

These provisions can be amended or waived by the owners of a majority of our outstanding shares as described above under “—Meetings; Approvals.”

In addition, LINN has agreed under our limited liability company agreement that neither it nor any ofthrough its subsidiaries, will take any action that would result in LINN and its subsidiaries ceasing to control the voting power of LinnCo except in connection with a Terminal Transaction in which LINN’s successor:

is treated as a partnership for U.S. federal income tax purposes; and

assumes all of LINN’s obligations under our limited liability company agreement and the Omnibus Agreement.

These covenants can be amended or waived by the owners of a majority of our outstanding shares as described under “—Meetings; Approvals” above.

Terminal Transactions Involving LINN

Mergers. If the LINN unitholders are asked to approve a merger of LINN with another entity, we will submit the merger for a vote of our shareholders and will vote our LINN units in the same manner that our shareholders vote (or refrain from voting) their shares.

Cash Consideration. In a merger involving LINN in which LINN unitholders receive cash, you will be entitled to receive any cash we receive for our LINN units, net of income taxes payable by us. In the event of an all-cash merger of LINN, we will dissolve and wind up our affairs after such distribution.

Non-Cash Consideration. In a merger involving LINN in which LINN unitholders receive securities of another entity, you will be entitled to receive the securities received in connection with such merger. In the event of such a merger in which LINN is not the surviving entity, we will dissolve and wind up our affairs unless:

LINN’s successor would be treated as a partnership for U.S. federal income tax purposes; and

the surviving entity agrees to assume the obligations of LINN under our limited liability company agreement and the Omnibus Agreement.

Tender Offers.If a third party makes a tender offer for LINN units, LINN may, but will not be obligated to, cooperate with such third party to extend such tender offer to our shareholders or otherwise facilitate participation of our shareholders in the tender offer for LINN units.

Going Private Transaction.If at any time a person owns more than 90% of the outstanding LINN units, such person may elect to purchase all, but not less than all, of the remaining outstanding LINN units at a price equal to the higher of the current market price (as defined in LINN’s limited liability company agreement) and

Index to Financial Statements

the highest price paid by such person or any of its affiliates for any LINN units purchased during the 90-day period preceding the date notice was mailed to the LINN unitholders informing them of such election. In this case, we will be required to tender all of our outstanding LINN units and distribute the cash we receive, net of income taxes payable by us, to our shareholders. Following such distribution, we will cancel all of our outstanding shares and dissolve and wind up our affairs.

Sale of All or Substantially All of LINN’s Assets.If LINN sells all or substantially all of its assets in one or more transactions for cash and makes a distribution of such cash to its unitholders, we will distribute the cash we receive, net of income taxes payable by us, to our shareholders. Following such distribution, we will cancel all of our outstanding shares and dissolve and wind up our affairs.

Change in Tax Treatment of LINN.If LINN or its successor ceases to be treated as a partnership for U.S. federal income tax purposes, LINN or such successor will have the right to cause us to merge with and into LINN, in which case each of our shareholders would receive a distribution in kind of the LINN units and other property we own, if any, after payments to creditors and satisfaction of other obligations.

The transactions described above are referred to as “Terminal Transactions.”

Limited Call Rights

If at any time LINN or any of its affiliates own 80% or more of our then-outstanding shares, LINN has the right, which it may assign to any of its affiliates, to purchase all, but not less than all, of our remaining outstanding shares as of a record date selected by LINN, on at least 10 but not more than 60 days notice. If LINN elects to exercise this purchase right, the purchase price per share will equal the greater of:

the highest cash price paid by LINN or any of its affiliates for any of our shares purchased within the 90 days preceding the date on which LINN first mails notice of its election to shareholders; and

the current market price as of the date three days before the date the notice is mailed.

If a person acquires more than 90% of the outstanding LINN units, such person may require us to tender all of our outstanding LINN units for cash, in which case we will distribute the cash we receive to our shareholders pro rata. Following such distribution, we will cancel all of our outstanding shares and dissolve and wind up our affairs. See “—Terminal Transactions Involving LINN—Going Private Transaction” above.

Merger, Sale or Other Disposition of Assets

Other than in connection with a Terminal Transaction, our board of directors is generally prohibited, without the prior approval of the holders of a majority of our outstanding common shares and by the holder(s) of our voting share(s) from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or otherwise.

Our board of directors may merge us into, or convey all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity that will be treated as a corporation for U.S. federal income tax purposes.

Our shareholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law in connection with any merger or consolidation, sale of all or substantially all of our assets or any other transaction or event.

Books and Records

We are required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax purposes, our year end is November 30.

Index to Financial Statements

We will furnish or make available to record holders of shares, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants in accordance with the requirements of the Securities Exchange Act of 1934 (the “Exchange Act.”). Except for our fourth quarter, we will also furnish or make available summary financial information in accordance with the requirements of the Exchange Act.

Right to Inspect Books and Records

In addition to the reports referred to above in “—Books and Records,” our limited liability company agreement provides that a shareholder can, for a purpose reasonably related to his interest as a shareholder, upon reasonable demand and at his own expense, have furnished to him:

a current list of the name and last known address of each shareholder;

a copy of our tax returns;

information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each shareholder and the date on which each became a shareholder; and

copies of our limited liability company agreement, our certificate of formation, related amendments and powers of attorney under which they have been executed.

Our board of directors may, and intends to, keep confidential from our shareholders information that it believes to be in the nature of trade secrets or other information, the disclosure of which our board of directors believes in good faith is not in our best interests, information that could damage our company or our business, or information that we are required by law or by agreements with a third party to keep confidential. These provisions are deemed to replace the default provisions under Section 18-305 of the LLC Act.

LINN’s Limited Liability Company Agreement

Organization

Linn Energy, LLC was formed in April 2005 and will remain in existence until dissolved in accordance with its limited liability company agreement.

Purpose

Under LINN’s limited liability company agreement, it is permitted to engage, directly or indirectly, in any activity that its board of directors approves and that a limited liability company organized under Delaware law lawfully may conduct; provided, that the board of directors shall not cause LINN to engage, directly or indirectly, in any business activities that it determines would cause it to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes.

Although LINN’s board of directors has the ability to cause it and its operating subsidiaries to engage in activities other than the exploitation, development and production of natural gas reserves, LINN’s board of directors has no current plans to do so. The board of directors is authorized in general to perform all acts it deems to be necessary or appropriate to conduct LINN’s business.

Board of Directors; Fiduciary Duties

LINN’s limited liability company agreement provides that its business and affairs shall be managed under the direction of its board of directors, which shall have the power to appoint its officers. The limited liability company agreement further provides that the authority and function of the board of directors and officers shall be identical to the authority and functions of a board of directors and officers of a corporation organized under the

Index to Financial Statements

Delaware General Corporation Law, or DGCL. Finally, LINN’s limited liability company agreement provides that except as specifically provided therein, the fiduciary duties and obligations owed to the limited liability company and to the members shall be the same as the respective duties and obligations owed by officers and directors of a corporation organized under the DGCL to their corporation and stockholders, respectively.

LINN’s limited liability company agreement permits affiliates of its directors to engage in other business interests or activities in preference to or to the exclusion of LINN and to engage in business interests that directly compete with LINN, provided that the affiliate does not engage in such competing businesses as a result of or using confidential information provided by or on behalf of LINN to such director. Additionally, LINN’s directors do not have any contractual obligation or express or implied legal duty to present business opportunities to LINN that become available to their affiliates, and neither LINN nor any of its subsidiaries or members have any rights in any business ventures of a director.

In addition, LINN’s limited liability company agreement establishes a conflicts committee of its board of directors, consisting solely of independent directors, which will be authorized to review transactions involving potential conflicts of interest. If the conflicts committee approves such a transaction, or if a transaction is on terms generally available from third parties or an action is taken that is fair and reasonable to LINN, unitholders will not be able to assert that such approval constituted a breach of fiduciary duties owed to them by LINN’s directors and officers.

Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney

By purchasing units in LINN, LinnCo will be admitted as a unitholder of LINN and will be deemed to have agreed to be bound by the terms of its limited liability company agreement. Pursuant to this agreement, each unitholder and each person who acquires a unit from a unitholder grants to LINN Energy’s Chief Executive Officer, President and Secretary (and, if appointed, a liquidator) a power of attorney to, among other things, execute and file documents required for its qualification, continuance or dissolution. The power of attorney also grants the Chief Executive Officer, President and Secretary (and, if appointed, a liquidator) the authority to make certain amendments to, and to make consents and waivers under and in accordance with, LINN’s limited liability company agreement.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “ —Limited Liability.”

Limited Liability

Unlawful Distributions. The LLC Act provides that a unitholder who receives a distribution and knew at the time of the distribution that the distribution was in violation of the LLC Act shall be liable to the company for the amount of the distribution for three years from the date of the distribution. Under the LLC Act, a limited liability company may not make a distribution to a unitholder if, after the distribution, all liabilities of the company, other than liabilities to unitholders with respect to their membership interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the company. For the purpose of determining the fair value of the assets of a company, the LLC Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the company only to the extent that the fair value of that property exceeds the nonrecourse liability. Under the LLC Act, an assignee who becomes a substituted unitholder of a company is liable for the obligations of his assignor to make contributions to the company, except the assignee is not obligated for liabilities unknown to him at the time he became a unitholder and that could not be ascertained from the limited liability company agreement.

Index to Financial Statements

Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which LINN Does Business. LINN’s subsidiaries currently conduct business in the States of Texas, Oklahoma, Kansas, Louisiana, New Mexico, Michigan, Illinois, California, North Dakota and Wyoming. They may decide to conduct business in other states, and maintenance of limited liability for LINN, as a member of its operating subsidiaries, may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying the subsidiaries to do business there. Limitations on the liability of unitholders for the obligations of a limited liability company have not been clearly established in many jurisdictions. LINN operates in a manner that its board of directors considers reasonable and necessary or appropriate to preserve the limited liability of its unitholders.

Voting Rights

The following matters require the unitholder vote specified below:

Election of members of the board of directors

LINN currently has seven directors. Its limited liability company agreement provides that it will have a board of not less than three and no more than eleven members. Holders of LINN units, voting together as a single class, will elect its directors. Please read “—Election of Members of LINN’s Board of Directors.”

Issuance of additional units

No approval right.

Amendment of the limited liability company agreement

Certain amendments may be made by LINN’s board of directors without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Limited Liability Company Agreement.”

Merger of LINN or the sale of all or substantially all of its assets

Unit majority.

Dissolution of LINN

Unit majority.

Issuance of Additional Securities

LINN’s limited liability company agreement authorizes it to issue an unlimited number of additional securities and authorizes it to buy securities for the consideration and on the terms and conditions determined by its board of directors without the approval of the unitholders.

From time to time, LINN may fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units LINN issues will be entitled to share pro rata with the then-existing holders of units in its distributions of available cash. In addition, the issuance of additional units or other equity securities may dilute the value of the interests of the then-existing holders of units in LINN’s net assets.

In accordance with Delaware law and the provisions of its limited liability company agreement, LINN may also issue additional securities that, as determined by its board of directors, may have special voting or other rights to which the units are not entitled.

Index to Financial Statements

The holders of units will not have preemptive or preferential rights to acquire additional units or other securities.

Election of Members of LINN’s Board of Directors

At each annual meeting of unitholders, members of LINN’s board of directors are elected by its unitholders and are subject to re-election on an annual basis.

Removal of Members of the Board of Directors

Any director may be removed, with or without cause, by the holders of a majority of the outstanding units then entitled to vote at an election of directors.

Amendment of the Limited Liability Company Agreement

General. Amendments to our limited liability company agreement may be proposed only by or with the consent of our board of directors. To adopt a proposed amendment, other than the amendments discussed below, our board of directors is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our unitholders to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:

enlarge the obligations of any unitholder without its consent, unless approved by at least a majority of the type or class of member interests so affected;

provide that LINN is not dissolved upon an election to dissolve LINN by the board of directors that is approved by a unit majority;

change the term of existence of LINN; or

give any person the right to dissolve LINN other than its board of directors’ right to dissolve it with the approval of a unit majority.

The provision of LINN’s limited liability company agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 75% of the outstanding units, voting together as a single class.

No Unitholder Approval. LINN’s board of directors may generally make amendments to its limited liability company agreement without the approval of any unitholder or assignee to reflect:

a change in LINN’s name, the location of its principal place of business, its registered agent or its registered office;

the admission, substitution, withdrawal or removal of members in accordance with its limited liability company agreement;

the merger of LINN or any of its subsidiaries into, or the conveyance of all of its assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in the legal form into another limited liability entity;

a change that the board of directors determines to be necessary or appropriate for LINN to qualify or continue its qualification as a company in which the members have limited liability under the laws of any state or to ensure that neither it, its operating subsidiaries nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes;

Index to Financial Statements

an amendment that is necessary, in the opinion of our counsel, to prevent LINN, members of its board, or its officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

an amendment that the board of directors determines to be necessary or appropriate for the authorization of additional securities or rights to acquire securities;

any amendment expressly permitted in the limited liability company agreement to be made by the board of directors acting alone;

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the limited liability company agreement;

any amendment that LINN’s board of directors determines to be necessary or appropriate for the formation by it of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by its limited liability company agreement;

a change in LINN’s fiscal year or taxable year and related changes;

a merger, conversion or conveyance effected in accordance with the limited liability company agreement; and

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, LINN’s board of directors may make amendments to its limited liability company agreement without the approval of any unitholder or assignee if its board of directors determines that those amendments:

do not adversely affect the unitholders (including any particular class of unitholders as compared to other classes of unitholders) in any material respect;

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the units are or will be listed for trading, compliance with any of which the board of directors deems to be in the best interests of LINN and its unitholders;

are necessary or appropriate for any action taken by the board of directors relating to splits or combinations of units under the provisions of the limited liability company agreement; or

are required to effect the intent expressed in this prospectus or the intent of the provisions of the limited liability company agreement or are otherwise contemplated by the limited liability company agreement.

Opinion of Counsel and Unitholder Approval. LINN’s board of directors will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to its unitholders or result in our being treated as an entity for U.S. federal income tax purposes if one of the amendments described above under “—No Unitholder Approval” should occur. No other amendments to LINN’s limited liability company agreement will become effective without the approval of holders of at least 90% of the units unless it obtains an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any unitholder.

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is

Index to Financial Statements

required to be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

LINN’s board of directors is generally prohibited, without the prior approval of the holders of a unit majority from causing it to, among other things, sell, exchange or otherwise dispose of all or substantially all of its assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of its subsidiaries, provided that its board of directors may mortgage, pledge, hypothecate or grant a securityNew Linn, other than New Linn’s 50% equity interest in all or substantially allRoan LLC.

Following the Riviera Separation, New Linn and Roan Holdings reorganized their ownership of its assets without that approval. The boardRoan LLC through the creation of directors may also sell all or substantially allcertain new entities and the consummation of LINN’s assets underadditional restructuring transactions. On the Effective Date, we consummated a foreclosure or other realization uponreorganization transaction pursuant to the encumbrances above without that approval.Master Reorganization Agreement by and among New Linn, Roan Holdings and Roan LLC. In connection with the Master Reorganization Agreement, we entered into the following agreements on the Effective Date:

If

a merger agreement (the “Linn Merger Agreement”) with New Linn and Linn Merger Sub #2, LLC (“Linn Merger Sub”), pursuant to which Linn Merger Sub merged with and into New Linn, with New Linn surviving the conditions specified in LINN’s limited liability companymerger as the Company’s wholly owned direct subsidiary, and the Legacy Linn Stockholders receiving an aggregate of 76,269,766 shares of our Class A common stock as merger consideration (the “Linn Merger”); and

a merger agreement are satisfied, LINN’s board of directors may merge LINN or any of its subsidiaries(the “Roan Holdco Merger Agreement” and, together with the Linn Merger Agreement, the “Merger Agreements”) with Roan Holdings, Roan Holdco and Linn Merger Sub #3, LLC (“Holdco Merger Sub”, pursuant to which, immediately after the Linn Merger, Holdco Merger Sub merged with and into or convey all of its assets to, a newly-formed entity ifRoan Holdco, with Roan Holdco surviving the merger as the Company’s wholly owned direct subsidiary, and Roan Holdings, the sole purposemember of thatRoan Holdco, receiving an aggregate of 76,269,766 shares of our Class A common stock as merger or conveyance isconsideration (the “Holdco Merger”).

We refer to effectthe Linn Merger, the Holdco Merger and the other transactions contemplated by the Merger Agreements and Master Reorganization Agreement as the “Reorganization.” On September 27, 2018, we amended and restated our certificate of incorporation and bylaws pursuant to the terms of the Master Reorganization Agreement and the Voting Agreement (as defined herein). The following diagram indicates our simplified ownership structure as of September 24, 2018, immediately following the closing of the Reorganization:

LOGO

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Historical Transactions with Affiliates

Contribution Agreement and Management Services Agreements

On August 31, 2017, we entered into the contribution agreement with Citizen and Old Linn, pursuant to which, among other things, Citizen and Old Linn contributed oil and natural gas properties within anarea-of-mutual-interest to us, in exchange for which each received a mere change50% equity interest in us.

In conjunction with the contribution agreement, the Company entered into MSAs with both Citizen and Old Linn. Under the MSAs, Citizen and Old Linn provided certain services in respect to the oil and natural gas properties they contributed to the Company. Such services included serving as operator of the oil and natural gas properties contributed, land administration, marketing, information technology and accounting services. As a result of Citizen and Old Linn continuing to serve as operator of the contributed assets and contracting directly with vendors for goods and services for operations, Citizen and Old Linn collected amounts due from joint interest owners for their share of costs and billed the Company for its legal form into another limited liability entity.share of costs. The unitholders are not entitled to dissenters’ rights of appraisalservices provided under the limited liability company agreement or applicable Delaware lawMSAs ended in April 2018 when the eventCompany took over as operator for the oil and natural gas properties contributed by Citizen and Old Linn. For the year ended December 31, 2018, the Company incurred approximately $10.0 million in charges related to the services provided under the MSAs.

Through April 2018, Citizen and Old Linn billed the Company for its share of a merger or consolidation, a sale of all or substantially alloperating costs in accordance with the MSAs. At December 31, 2017, the Company had $55.5 million and $46.5 million due to Old Linn and Citizen, respectively. At December 31, 2017, the Company had $19.0 million due to Old Linn and Citizen for revenue suspense associated with the oil and gas properties contributed to the Company.

In conjunction with the conclusion of the assets or any other transaction or event.MSAs, the Company assumed certain working capital accounts, totaling $112.6 million, associated with the properties contributed from Citizen and Old Linn.

TerminationCitizen Energy II, LLC

Atlas, LLC (“Atlas”) provided us supervisory services throughout drilling and Dissolutioncompletion operations. Atlas is jointly owned by a director and an employee of Citizen. For the year ended December 31, 2017, we incurred $2.3 million in charges related to services provided by Atlas.

LINN will continue asJones Energy, Inc.

In May 2018, Roan LLC elected to participate with its interest in a company until terminated under its limited liability company agreement. LINN will dissolve upon: (1)Jones Energy, Inc. well in Canadian County, Oklahoma, and, in connection, Roan LLC has paid Jones Energy, Inc. a total of $0.7 million during the electionyear ended December 31, 2018. As of its boardDecember 31, 2018, JVL, an affiliate of directors to dissolve it if approved by the holders of a unit majority; (2) the sale, exchange or other disposition of all or substantially allour significant stockholder, Roan Holdings, held 16.34% of the assetscombined voting power of Jones Energy, Inc. Messrs. Lovoi and properties of LINN and its subsidiaries; or (3) the entry of a decree of judicial dissolution of LINN.

Liquidation and Distribution of Proceeds

Upon dissolution of LINN, the liquidator authorized to wind up LINN’s affairs will, acting with all of the powersLoyd were members of the board of directors of LINN thatJones Energy, Inc. until September 2018 and Mr. Lovoi is the liquidator deems necessary or desirable in its judgment, sell or otherwise disposesole member of, LINN’s assets. The liquidator will first apply the proceedsand exercises investment management control over JVL.

Riviera Resources, Inc.

Messrs. Taylor, Lederman and Bonanno are on our board of liquidation to the payment of LINN’s creditorsdirectors and then distribute any remaining proceeds to the LINN unitholders in accordance with, and to the extent of, the positive balances in their respective capital accounts in their units, as adjusted to reflect any gain or loss upon the sale or other disposition of LINN’s assets in liquidation. The liquidator may defer liquidation or distribution of LINN’s assets for a reasonable period of time or distribute assets to unitholders in kind if it determines that a sale would be impractical or would cause undue loss to LINN’s unitholders.

Anti-Takeover Provisions

LINN’s limited liability company agreement contains specific provisions that are intended to discourage a person or group from attempting to take control of LINN without the approval of the board of directors. Specifically,directors of Riviera. Additionally, certain of our principal stockholders are also significant stockholders in Riviera.

Natural Gas Dedication Agreement. The Company has a natural gas dedication agreement with Blue Mountain Midstream LLC (“Blue Mountain”), which is a subsidiary of Riviera. Sales to Blue Mountain during the year ended December 31, 2017 are reflected as natural gas sales – affiliates and natural gas liquids sales – affiliates in the accompanying statements of operations. Sales to Blue Mountain during the year ended December 31, 2018 and the three months ended March 31, 2019 were approximately $66 million and $18.4 million, respectively.

Water Management Services Agreement. In January 2019, the Company entered into a water management services agreement with Blue Mountain. Under this agreement, Blue Mountain will provide water management services including pipeline gathering, disposal, treatment and redelivery of recycled water. The agreement provides for an acreage dedication for water management services through January 2029. Blue Mountain began providing services under this agreement in April 2019.

Transition Services Agreement. On August 7, 2018, New Linn entered into a Transition Services Agreement (the “Riviera TSA”) with Riviera to facilitate an orderly transition following the Riviera Separation. During the term of the Riviera TSA, Riviera provided New Linn with certain finance, financial reporting, information technology, investor relations, legal, payroll, tax and other services. Riviera reimbursed New Linn for, or paid on New Linn’s behalf, all direct and indirect costs and expenses incurred by New Linn during the term of the Riviera TSA in connection with the fees for any such services. The Riviera TSA terminated according to its terms on the Effective Date.

Riviera Separation and Distribution Agreement.On August 7, 2018, the Company’s predecessor, New Linn, entered into that certain Separation and Distribution Agreement by and between New Linn and Riviera, following which Riviera holds, directly or through its subsidiaries, substantially all of the assets of Old Linn, other than Old Linn’s 50% equity interest in Roan LLC. Following the internal reorganization, New Linn distributed all of the outstanding shares of common stock of Riviera to the Legacy Linn Stockholders on a pro rata basis, including the Elliott Funds, the Fir Tree Funds and the York Capital Funds, each a principal stockholder of the Company. On September 21, 2018, the Elliott Funds, the Fir Tree Funds and the York Capital Funds owned approximately 20.8%, 19.4% and 12.1%, respectively, of Riviera. Immediately following the Riviera Separation, Riviera’s common stock closed at $23.25 per share, valuing the stock received by each of the Elliott Funds, the Fir Tree Funds and the York Capital Funds at approximately $367.2 million, $342.1 million and $197.1 million, respectively.

Tax Matters Agreement.In conjunction with the Reorganization, the Company’s predecessor, New Linn, entered into a tax matters agreement with Riviera (the “Riviera TMA”). The Riviera TMA, in part, provides for indemnification of the Company and entitlement of refunds by Riviera of certain taxes related to New Linn prior to the spinoff of assets from New Linn to Riviera. As a result of the Riviera TMA and an estimated overpayment of federal taxes by New Linn, the Company paid $7.6 million to Riviera during the three months ended March 31, 2019.

Corporate Office Lease. During 2018, we entered into a lease for office space in Oklahoma City, Oklahoma that is owned by a subsidiary of Riviera. The lease has an initial term of five years. Under this lease, we paid $0.5 million during the year ended December 31, 2018 and $0.3 million for the three months ended March 31, 2019. As of March 31, 2019, total remaining payments are $7.8 million.

Legal expenses. During the year ended December 31, 2018, we also reimbursed Riviera $1.8 million for legal services incurred on the behalf of Roan in connection with the Reorganization.

Stockholders’ Agreement

In connection with the Reorganization, on the Effective Date, we entered into a stockholders’ agreement (the “Stockholders’ Agreement”) with Roan Holdings and the Elliot funds, the Fir Tree funds and the York Capital funds (each such group of affiliated funds, a “Principal Linn Stockholder,” and together with Roan Holdings, the “principal stockholders”), which will govern certain rights and obligations of the principal stockholders following the Reorganization.

Pursuant to the Stockholders’ Agreement, until the earlier of (i) our 2020 annual general meeting of stockholders (the “2020 annual meeting”) and (ii) with respect to the applicable Principal Linn Stockholder, the date on which the applicable Principal Linn Stockholder ceases to beneficially own at least 5% of our outstanding

shares of Class A common stock, each Principal Linn Stockholder shall have the right to designate one director (each, a “Linn Stockholder Director”) to our board of directors and to fill any vacancy on the board of directors due to the death, disability, resignation or removal of any Linn Stockholder Director designated by such principal Linn Stockholder; provided, however, that at all times, at least one Linn Stockholder Director shall be an “independent director” who meets the independence standards of any national securities exchange on which our Class A common stock is or will be listed and Rule10A-3 of the Exchange Act. If a Principal Linn Stockholder’s designation rights terminate as a result of no longer beneficially owning at least 5% of our outstanding shares of Class A common stock, the applicable Linn Stockholder Director shall be entitled to continue serving on the board of directors until the end of such Linn Stockholder Director’s term.

The Stockholders’ Agreement also provides that until the earlier of (i) the 2020 annual meeting and (ii) the date on which Roan Holdings ceases to beneficially own at least 5% of the outstanding shares of Class A common stock, Roan Holdings shall have the right to designate one independent director (the “Roan Holdings Independent Director”) to the board of directors (subject to the consent of the Principal Linn Stockholders) and to fill any vacancy on the board of directors due to the death, disability, resignation or removal of any Roan Holdings Independent Director.

In addition, the Stockholders’ Agreement provides that until the earlier of (i) the 2020 annual meeting and (ii) the date on which Roan Holdings ceases to beneficially own at least 5% of the outstanding shares of Class A common stock, Roan Holdings shall have the right to designate to the board of directors a number of directors (each, a “Roan Holdings Director”) equal to: (i) if Roan Holdings beneficially owns at least 30% of the outstanding shares of Class A common stock, four directors; (ii) if Roan Holdings beneficially owns at least 15% but less than 30% of the outstanding shares of Class A common stock, three directors; and (iii) if Roan Holdings beneficially owns at least 5% but less than 15% of the outstanding shares of Class A common stock, two directors, and, in each case, to fill any vacancy on the board of directors due to the death, disability, resignation or removal of any Roan Holdings Director; provided, however, that at all times, at least one Roan Holdings Director shall be an independent director. If Roan Holdings’ designation rights terminate as a result of no longer beneficially owning at least 5% of our outstanding shares of Class A common stock, the Roan Holdings Directors shall be entitled to continue serving on the board of directors until the end of such Roan Holdings Directors’ terms.

Additionally, pursuant to the Stockholders’ Agreement we have agreed, to the fullest extent permitted by applicable law (including with respect to any applicable fiduciary duties under Delaware law), to take all necessary action to effectuate the above by: (i) including the persons designated pursuant to the Stockholders’ Agreement in the slate of nominees recommended by the board of directors for election at any meeting of stockholders called for the purpose of electing directors, (ii) nominating and recommending each such individual to be elected as a director as provided herein, (iii) soliciting proxies or consents in favor thereof, and (iv) without limiting the foregoing, otherwise using its reasonable best efforts to cause such nominees to be elected to the board of directors, including providing at least as high a level of support for the election of such nominees as it provides to any other individual standing for election as a director.

Roan LLC Agreement

On the Effective Date, in connection with the Reorganization, New Linn and Roan Holdco amended and restated the limited liability company agreement providesof Roan LLC to cause Roan LLC to be a manager-managed limited liability company, with Roan Inc. serving as the sole manager.

Registration Rights Agreement

On the Effective Date, in connection with the Reorganization, we entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with certain significant holders of our Class A common stock identified on the signature pages thereto (the “Holders”).

Pursuant to, and subject to the limitations set forth in, the Registration Rights Agreement, we agreed, no later than thirty (30) days following the Reorganization, to register under federal securities laws the public offer and resale of the shares of Class A common stock held by the Holders or certain of their affiliates or permitted transferees on a shelf registration statement.

In addition, pursuant to the Registration Rights Agreement, certain of the Holders have the right to require us, subject to certain limitations set forth therein, to effect a distribution of any or all of their shares of Class A common stock by means of an underwritten offering. Further, subject to certain exceptions, if at any time we propose to register an offering of its equity securities or conduct an underwritten offering, whether or not for our own account, then we must notify the Holders of such proposal reasonably in advance of the anticipated filing date or commencement of the underwritten offering, as applicable, to allow them to include a specified number of their shares in that LINNregistration statement or underwritten offering, as applicable.

These registration rights are subject to certain conditions and limitations, including our right to limit the number of shares to be included in a registration statement or underwritten offering and our right to delay or withdraw a registration statement under certain circumstances. We will electgenerally pay all registration expenses in connection with our obligations under the Registration Rights Agreement other than underwriting discounts and commissions related to havethe shares sold by the selling stockholders, regardless of whether a registration statement is filed or becomes effective.

We are generally required to maintain the effectiveness of the shelf registration statement with respect to any Holder until the date on which there are no longer any Registrable Securities (as defined in the Registration Rights Agreement) outstanding.

Pursuant to the Registration Rights Agreement, certain of the Holders agreed, for a period of 90 days from the Effective Date, not to (i) sell, transfer or otherwise dispose of any shares of Class A common stock or publicly disclose the intention to make any offer, sale or disposition, or (ii) make any demand for or exercise any right with respect to the registration of any shares of Class A common stock other than (A) in connection with an underwritten offering pursuant to the terms of the Registration Rights Agreement, (B) in connection with the filing of any registration statement effected pursuant to the terms of the Registration Rights Agreement, (C) sales, transfers and dispositions of shares of Class A common stock up to an aggregate of 10% of the Class A common stock outstanding on the Effective Date and (D) distributions of shares of Class A common stock to members, partners or stockholders of such Holders.

Voting Agreement

Following the Linn Merger and the Holdco Merger, on the Effective Date, in connection with the Reorganization, we entered into a voting agreement (the “Voting Agreement”) with the principal stockholders. Pursuant to the terms of the Voting Agreement, on September 27, 2018, the principal stockholders voted all of their outstanding shares of our Class A common stock in favor of the adoption and approval of our second amended and restated certificate of incorporation, our second amended and restated bylaws, the amended and restated certificate of incorporation of New Linn and the second amended and restated bylaws of New Linn, and such documents were adopted and approved, effective as of the September 27, 2018.

Master Reorganization Agreement

On the Effective Date, we consummated the Master Reorganization Agreement by and among New Linn, Roan Holdings and Roan LLC. In connection with the Master Reorganization Agreement, we entered into the following agreements on the Effective Date:

the Linn Merger Agreement with New Linn and Linn Merger Sub, pursuant to which the Linn Merger occurred; and

the Roan Holdco Merger Agreement with Roan Holdings, Roan Holdco and Holdco Merger Sub, pursuant to which, immediately after the Linn Merger, the Holdco Merger occurred.

The Linn Merger was effected pursuant to Section 203251(g) of the Delaware General Corporation Law, apply to transactionswhich provides for the formation of a holding company without a vote of the stockholders of the constituent corporations.

Procedures for Approval of Related Party Transactions

A “Related Party Transaction” is a transaction, arrangement or relationship in which an interested unitholder (as described below) seekswe or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

any person who is known by us to enterbe the beneficial owner of more than 5% of our Class A common stock;

any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling,mother-in-law,father-in-law,son-in-law,daughter-in-law,brother-in-law orsister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A common stock; and

any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

Our board of directors adopted a written related party transactions policy. Pursuant to this policy, our audit committee will review all material facts of all future Related Party Transactions and either approve or disapprove entry into the Related Party Transaction, subject to certain limited exceptions. In determining whether to approve or disapprove entry into a mergerRelated Party Transaction, our audit committee shall take into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances; and (ii) the extent of the Related Person’s interest in the transaction. Further, the policy will require that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations.

DESCRIPTION OF CAPITAL STOCK

The authorized capital stock of Roan Resources, Inc. consists of 800,000,000 shares of Class A common stock, $0.001 par value per share, of which 152,539,532 shares are issued and outstanding and 50,000,000 shares of preferred stock, $0.001 par value per share, of which no shares are issued and outstanding.

The following summary of the capital stock and our second amended and restated certificate of incorporation and second amended and restated bylaws does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our second amended and restated certificate of incorporation and second amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus forms a part.

Description of Class A Common Stock

Except as provided by law or in a preferred stock designation, holders of Class A common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of Class A common stock are not entitled to vote on any amendment to the second amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to our second amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the DGCL. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of Class A common stock are entitled to receive ratably in proportion to the shares of Class A common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of Class A common stock are fully paid andnon-assessable.

The holders of Class A common stock have no preferences or rights of conversion, exchange,pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to Class A common stock. In the event of any voluntary or involuntary liquidation, dissolution orwinding-up of our affairs, holders of Class A common stock will be entitled to share ratably in our assets in proportion to the shares of Class A common stock held by them that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any.

Description of Preferred Stock

Our second amended and restated certificate of incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.001 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Second Amended and Restated Certificate of Incorporation, Our Second Amended and Restated Bylaws and Delaware Law

Some provisions of Delaware law, our second amended and restated certificate of incorporation and our second amended and restated bylaws contain provisions that could make the following transactions more

difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

Section 203 of the DGCL prohibits a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with it. Under this provision, suchany interested stockholder for a holder will not be permitted to enter into a merger or business combination with LINNperiod of three years following the date that the stockholder became an interested stockholder, unless:

 

prior to such time, LINN’sthe transaction is approved by the board of directors approved eitherbefore the business combination ordate the transactioninterested stockholder attained that resulted in the unitholder’s becoming an interested unitholder;status;

 

upon consummation of the transaction that resulted in the unitholder’sstockholder becoming an interested unitholder,stockholder, the interested unitholderstockholder owned at least 85% of the voting stock of the corporation outstanding units at the time the transaction commenced, excluding for purposes of determining the number of units outstanding those units owned:

Index to Financial Statements

by persons who are directors and also officers;

by employee unit plans in which employee participants do not have the right to determine confidentially whether units held subject to the plan will be tendered in a tender or exchange offer;commenced; or

 

aton or subsequent toafter such time the business combination is approved by the board of directors and authorized at an annual or speciala meeting of the unitholders, and notstockholders by written consent, by the affirmative vote of at least a majoritytwo-thirds of the outstanding voting unitsstock that areis not owned by the interested unitholder.stockholder.

We will continue to elect to not be subject to the provisions of Section 203 defines “business combination”of the DGCL.

Our Second Amended and Restated Certificate of Incorporation and Our Second Amended and Restated Bylaws

Provisions of our second amended and restated certificate of incorporation and our second amended and restated bylaws may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to include:be in their best interests. Therefore, these provisions could adversely affect the price of our Class A common stock.

Among other things, our second amended and restated certificate of incorporation and second amended and restated bylaws:

 

any merger or consolidation involving the company and the interested unitholder;

any sale, transfer, pledge or other disposition of 10% or more of the assets of the company involving the interested unitholder;

subjectestablish advance notice procedures with regard to certain exceptions, any transaction that results in the issuance or transfer by the company of any units of the companystockholder proposals relating to the interested unitholder;

any transaction involvingnomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the company that hasmeeting at which the effect of increasing the proportionate share of the units of any class or series of the company beneficially owned by the interested unitholder; or

the receipt by the interested unitholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the company.

In general, by referenceaction is to Section 203, an “interested unitholder” is any entity or person who or which beneficially owns (or within three years did own) 15% or more of the outstanding voting units of the company and any entity or person affiliated with or controlling or controlled by such entity or person.

The existence of this provision would be expectedtaken. Generally, to have an anti-takeover effect with respect to transactions not approved in advance by LINN’s board of directors, including discouraging attempts that might result in a premium over the market price for units held by unitholders.

Limited Call Right

Ifbe timely, notice must be received at any time any person owns more than 90% of the then-issued and outstanding membership interests of any class, such person will have the right, which it may assign in whole or in part to any of its affiliates or to LINN, to acquire all, butour principal executive offices not less than all, of the remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by LINN’s management, on at least 10 but not more than 60 days’ notice. The unitholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law if this limited call right is exercised. The purchase price in the event of this purchase is the greater of:

the highest cash price paid by such person for any membership interests of the class purchased within the 90 days preceding the date on which such person first mails notice of its election to purchase those membership interests; or

the closing market price as of the date three days before the date the notice is mailed.

As a result of this limited call right, a holder of membership interests in LINN may have his membership interests purchased at an undesirable time or price. Please read “Risk Factors—Risks Inherent in an Investment in LinnCo—Your shares are subject to limited call rights that could result in your having to involuntarily sell your shares at a time or price that may be undesirable.” The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material U.S. Federal Income Tax Consequences.”

Index to Financial Statements

Meetings; Voting

All notices of meetings of unitholders shall be sent or otherwise given in accordance with Section 11.4 of LINN’s limited liability company agreement not less than 10 nor more than 60120 days beforeprior to the first anniversary date of the meeting. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted (no business other than that specified in the notice may be transacted) or (ii) in the case of the annual meeting thosefor the preceding year. Our second amended and restated bylaws will specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters whichbefore the stockholders at an annual or special meeting;

provide our board of directors at the time of giving the notice, intendsability to presentauthorize undesignated preferred stock. This ability makes it possible for action by the unitholders (but any proper matter may be presented at the meeting for such action). The notice of any meeting at which directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, theour board of directors intends to present for election. Any previously scheduled meetingissue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the unitholderseffect of deferring hostile takeovers or delaying changes in control or management of our company;

provide that the authorized number of directors may be postponed, and any special meeting of the unitholders may be canceled,changed only by resolution of the board of directors;

on or after the 2020 annual meeting, provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors upon public notice giventhen in office, even if less than a quorum, or, prior to the 2020 annual meeting, by certain principal stockholders, for so long as such principal stockholders and their affiliates collectively beneficially own a certain amount of the outstanding shares of our Class A common stock;

provide for our board of directors to be divided into two classes of directors, with the first class serving a term ending on the date previously scheduled for suchof the Company’s 2019 annual general meeting of unitholders.stockholders and the second class serving a term ending on the date of the 2020 annual meeting. Following the 2020 annual meeting, the board of directors will cease to be classified. This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors;

Any

provide that special meetings of our stockholders may only be called by the board of directors;

provide that any action required or permitted to be taken by the unitholdersstockholders must be effected at a duly called annual or special meeting of unitholdersstockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series;

provide that the affirmative vote of the holders of a majority of the voting power of all then outstanding Class A common stock entitled to vote generally in the election of directors shall be required to remove any or all of the directors from office with or without cause; and

at any time prior to the 2020 annual meeting,

or until the applicable Principal Linn Stockholder ceases to beneficially own at least 5% of our outstanding shares of Class A common stock, each Principal Linn Stockholder shall have the right to designate one director to our board of directors and to fill any vacancy on the board of directors due to the death, disability, resignation or removal of such Linn Stockholder Director designated by such unitholders.Principal Linn Stockholder;

Meetings

or until the Roan Holdings ceases to beneficially own at least 5% of the unitholders mayoutstanding shares of Class A common stock, Roan Holdings shall have the right to designate one independent director to the board of directors (subject to the consent of the Principal Linn Stockholders) and to fill any vacancy on the board of directors due to the death, disability, resignation or removal of such Roan Holdings Independent Director;

or until the Roan Holdings ceases to beneficially own at least 5% of the outstanding shares of Class A common stock, Roan Holdings shall have the right to designate to the board of directors a number of directors equal to: (i) if Roan Holdings beneficially owns at least 30% of the outstanding shares of Class A common stock, four directors; (ii) if Roan Holdings beneficially owns at least 15% but less than 30% of the outstanding shares of Class A common stock, three directors; and (iii) if Roan Holdings beneficially owns at least 5% but less than 15% of the outstanding shares of Class A common stock, two directors, and, in each case, to fill any vacancy on the board of directors due to the death, disability, resignation or removal of any such Roan Holdings Director; and

provide that the then-current chief executive officer of Roan Inc. be designated to serve as a member of the board of directors.

Amendment of the Second Amended and Restated Bylaws

The second amended and restated certificate of incorporation and the second amended and restated bylaws grant to the board of directors the power to adopt, amend, restate or repeal the second amended and restated bylaws, as permitted under the DGCL, provided that any adoption, alternation or repeal by the board of directors shall require (i) prior to the date of the 2020 annual meeting, a vote of equal to or great than 66 2/3% of the board of directors, and (ii) on and after the date of the 2020 annual meeting, only be called by a vote of a majority of the board of directors. UnitholdersThe stockholders may adopt, amend, restate or repeal the second amended and restated bylaws, subject to the then-applicable terms and conditions of the Stockholders’ Agreement, but only by a vote eitherof holders of at least 66 2/3% in personvoting power of the outstanding shares of stock entitled to vote thereon, voting together as a single class in addition to any approval required by law, the Bylaws or by proxy at meetings. Thethe terms of any preferred stock. Any amendment or waiver of any provision of the Bylaws that adversely affects the rights, preferences or privileges of the holders of the Preferred Stock in any material respect requires the affirmative vote of a majority of the outstanding unitsshares of Preferred Stock outstanding as of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holdersinitial issuance.

Corporate Opportunity

Under our second amended and restated certificate of a greater percentage of the units, in which case the quorum shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in LINN, although additional units having special voting rights could be issued. Please read “—Issuance of Additional Securities.” Units held in nominee or street name accounts will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under the limited liability company agreement will be deliveredincorporation, to the record holderextent permitted by LINN or by the transfer agent.law:

Non-Citizen Assignees; Redemption

If LINN orour principal stockholders and each of their respective affiliates (including portfolio investments of any of its subsidiaries is or becomes subject to federal, state or local laws or regulations that, in the reasonable determination of the board of directors, create a substantial risk of cancellation or forfeiture of any property that it has an interest in because of the nationality, citizenship or other related status of any unitholder or assignee, LINN may redeem, upon 30 days’ advance notice, the units held by the unitholder or assignee at their current market price. To avoid any cancellation or forfeiture, the board of directors may require each unitholder or assignee to furnish information about his nationality, citizenship or related status. If a unitholder or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or the board of directors determines after receipt of the information that the unitholder or assignee is not an eligible citizen, the unitholder or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted unitholder, a non-citizen assignee does notthem) have the right to, directand have no duty to abstain from exercising such right to, conduct business with any business that is competitive or in the votingsame line of his unitsbusiness as us, do business with any of our clients or customers, or invest or own any interest publicly or privately in, or develop a business relationship with, any business that is competitive or in the same line of business as us;

if our principal stockholders or any of their respective affiliates (including portfolio investments of any of them) acquire knowledge of a potential transaction that could be a corporate opportunity, they have no duty to offer such corporate opportunity to us; and may not receive distributions

we have renounced any interest or expectancy in, kind uponor in being offered an opportunity to participate in, such corporate opportunities.

Forum Selection

Our second amended and restated certificate of incorporation provides that unless we consent in writing to the liquidationselection of LINN.

an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

Index

any derivative action or proceeding brought on our behalf;

us or our stockholders;

Exculpation and Indemnification

Notwithstanding any express or impliedaction asserting a claim against us arising pursuant to any provision of itsthe DGCL, our second amended and restated certificate of incorporation or our second amended and restated bylaws; or

any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

The forum selection clause is intended to apply “to the fullest extent permitted by applicable law” to the above-specified types of actions and proceedings, including—to the extent permitted by the federal securities

laws—to lawsuits asserting both the above-specified claims and federal securities claims. However, application of the forum selection clause may in some instances be limited by applicable law. Section 27 of the Exchange Act provides: “The district courts of the United States ... shall have exclusive jurisdiction of violations of [the Exchange Act] or the rules and regulations thereunder, and of all suits in equity and actions at law brought to enforce any liability company agreement, or duty created by [the Exchange Act] or the rules and regulations thereunder.” As a result, the exclusive forum provision will not apply to actions arising under the Exchange Act or the rules and regulations thereunder. However, Section 22 of the Securities Act provides for concurrent federal and state court jurisdiction over actions under the Securities Act and the rules and regulations thereunder, subject to a limited exception for certain “covered class actions” as defined in Section 16 of the Securities Act and interpreted by the courts. Accordingly, we believe that the exclusive forum provision would apply to actions arising under the Securities Act or the rules and regulations thereunder, except to the extent a particular action fell within the exception for covered class actions or one of the exceptions in the second amended and restated certificate of incorporation described above otherwise applied to such action, which could occur if, for example, the action also involved claims under the Exchange Act. Our amended and restated certificate of incorporation also provides that any other legal dutyperson or obligation, noneentity purchasing or otherwise acquiring any interest in shares of LINN’s officers, directors or affiliatesour capital stock will be liabledeemed to LINN, LINN’s affiliateshave notice of, and to have consented to, this forum selection provision. Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or any other personmore actions or proceedings described above, a court could rule that this provision in our second amended and restated certificate of incorporation is inapplicable or unenforceable, including with respect to claims arising under the federal securities laws. Stockholders will not be deemed, by operation of the forum selection clause alone, to have waived claims arising under the federal securities laws and the rules and regulations thereunder.

Limitation of Liability and Indemnification Matters

Our second amended and restated certificate of incorporation limits the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of thetheir fiduciary duty as directors, except for liabilities:

for any breach of their duty of loyalty to LINNus or its members, our stockholders;

for acts or omissions not in good faith or involvingwhich involve intentional misconduct or a knowing violation of law,law;

for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

for any transaction from which athe director derived an improper personal benefit. Additionally, LINN’s

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our second amended and restated bylaws also provide that we will indemnify our directors will not be responsible for any misconduct or negligence on the part of an agent appointed by LINN’s board of directors in good faith.

Under the terms of its limited liability company agreement and subject to specified limitations, LINN will indemnifyofficers to the fullest extent permitted by Delaware law. Our second amended and restated bylaws also will permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law fromwould permit indemnification. We have entered into indemnification agreements with each of our current directors. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law

against liability that may arise by reason of their service to us, and against all losses,to advance expenses (including attorneys’ fees), judgments, fines, penalties, interest, settlement amounts, claims, damages or similar events any director or officer, or while servingincurred as a director or officer,result of any person who is or was servingproceeding against them as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trusteeto which they could be indemnified. We believe that the limitation of LINN or any of its affiliates. However, such directors, officers and persons are only entitled to indemnification if they acted in good faith and in a manner reasonably believed toliability provision that will be in (or not opposed to) LINN’s best interestsour second amended and restated certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Registration Rights

For a description of registration rights with respect to our Class A common stock, please see the information under the heading “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

Stockholders’ Agreement

For a description of rights of certain stockholders with respect to our Class A common stock, please see the information under the heading “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.”

Transfer Agent and Registrar

The transfer agent and registrar for our Class A common stock is American Stock Transfer & Trust Company, LLC.

Listing

Our Class A common stock trades on the NYSE under the symbol “ROAN”.

SHARES ELIGIBLE FOR FUTURE SALE

As of May 24, 2019, we have 152,539,532 shares of our Class A common stock outstanding none of which are freely tradeable without restriction or registration under the Securities Act. We are filing the registration statement of which this prospectus forms a part to register shares under the Securities Act on behalf of the selling stockholders. All other shares of our Class A common stock, except for shares of Class A common stock issuable under the MIP, are “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be resold without resold or transferred unless such shares have been registered under the Securities Act or an exemption from registration is available, including exemptions in Rule 144. Future sales of our Class A common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our Class A common stock prevailing from time to time.

Registration Rights Agreement

For a description of registration rights with respect to our Class A common stock, see the information under the heading “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any criminal proceeding or action, had no reasonable causetime during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months (including any period of consecutive ownership of precedingnon-affiliated holders) would be entitled to believe that such conduct was unlawful. The terminationsell those shares, subject only to the availability of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere shall not itself create a presumption that such good faith and reasonable belief standards were not met. Additionally, LINN may indemnify anycurrent public information about us. Anon-affiliated person who is or was an employee (other than an officer) or agenthas beneficially owned restricted securities within the meaning of LINNRule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a partynumber of shares that does not exceed the greater of one percent of the then outstanding shares of our Class A common stock or the average weekly trading volume of our Class A common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to a threatened, pending or completed action, suit or proceeding, tocertain manner of sale provisions, notice requirements and the extent permitted by law and authorized by LINN’s boardavailability of directors.current public information about us.

Any indemnificationRule 701

In general, under Rule 701 under the limited liability company agreement will only be outSecurities Act, any of LINN’s assets. LINN is authorized to purchase insurance against liabilities asserted against and expenses incurred byour employees, directors, officers, and personsconsultants or advisors who purchase or otherwise receive shares from us in connection with LINN’s activitiesa compensatory stock or their activitiesoption plan or other written agreement before the effective date of our registration statement on behalf of LINN, regardless of whether it would haveFormS-8 under the powerSecurities Act to indemnifyregister such shares issued or issuable under the person against liabilities under its limited liability company agreement.

Books and Reports

LINN is requiredMIP are entitled to keep appropriate books of its business at its principal offices. The books are maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, LINN’s fiscal year is the calendar year.

LINN will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by its independent public accountants. Except for our fourth quarter, LINN will also furnish or make available summary financial information withinsell such shares 90 days after the closeeffective date of each quarter.

LINNsuch registration statement in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case ofnon-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will furnish each record holderapply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of a unitthe Exchange Act, along with information reasonably required for tax reporting purposes within 90 daysthe shares acquired upon exercise of such options, including exercises after the closedate of each calendar year.this prospectus.

Long-Term Incentive Plan

We have filed a registration statement onForm S-8 under the Securities Act to register stock issuable under the MIP. This information is expected to be furnished in summary form so that some complex calculations normally required of unitholders can be avoided. LINN’s ability to furnish this summary information to unitholders will dependregistration statement on the cooperation of unitholders in supplying it with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies LINN with information.

Right To Inspect LINN’s Books and RecordsForm S-8

LINN’s limited liability company agreement provides that a unitholder can, was effective upon filing. Accordingly, shares registered under such registration statement are available for a purpose reasonably related to his interest as a unitholder, upon reasonable demand and at his own expense, have furnished to him:

a current list of the name and last known address of each unitholder;

Index to Financial Statements

a copy of LINN’s tax returns;

information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each unitholder and the date on which each became a unitholder;

copies of the limited liability company agreement, the certificate of formation of LINN, related amendments and powers of attorney under which they have been executed;

information regarding the status of LINN’s business and financial condition; and

any other information regarding its affairs as is just and reasonable.

LINN’s board of directors may, and intends to, keep confidential from its unitholders information that it believes to be in the nature of trade secrets or other information, the disclosure of which the board of directors believes in good faith is not in LINN’s best interests, information that could damage LINN or its business, or information that it is required by law or by agreements with a third party to keep confidential.

Comparison of LINN’s Units with Our Shares

The following table compares important features of the LINN units with our shares.

LINN Units

LinnCo Shares

Numbers of units and shares

         units outstanding as of                     , 2012.

One voting share currently outstanding.

                 shares to be issued in this offering.

Distributions and Dividends

On a quarterly basis, LINN is required to distribute to the owners of all classes of its units an amount equal to its available cash.

On a quarterly basis, LinnCo is required to pay a dividend equal to the amount of cash received from LINN in respect of the LINN units owned by LinnCo, less reserves for income taxes payable by LinnCo.

For the periods ending December 31, 2012, 2013, 2014 and 2015, we estimate that LinnCo’s income tax liability will not exceed     % of the cash distributed to LinnCo.

DissolutionLINN will dissolve upon: (1) the election of its board of directors to dissolve it if approved by the holders of a unit majority; (2) the sale exchange or other disposition of all or substantially all of the assets and properties of LINN and its subsidiaries; or (3) the entry of a decree of judicial dissolution of LINN.We will be dissolved and wound up only (1) upon entry of a judicial decree, (2) upon the approval by the owner(s) of the voting share(s) and by the holders of a majority of the outstanding shares of the class sold in this offering, voting as separate classes, (3) if we cease to own any LINN units (whether as a result of a merger of LINN or otherwise) and the owner(s) of the voting share(s) approve such dissolution, (4) in the event of a sale or other disposition of all or substantially all of our assets other than

Index to Financial Statements

LINN Units

LinnCo Shares

in connection with certain non-cash mergers involving LINN or (5) if at any time we have no members, unless a member is admitted to LinnCo and LinnCo is continued without dissolution in accordance with the LLC Act. In the event that we are dissolved, our affairs will be wound up and all our remaining assets, after payments to creditors and satisfaction of other obligations, will be distributed to the holders of the outstanding shares.
If LINN or its successor is treated as a corporation for U.S. federal income tax purposes, LINN or such successor will have the right to cause us to merge with and into LINN, in which case our shareholders would receive distributions in kind of LINN units and other property we own, if any, after payments to creditors and satisfaction of other obligations.

Voting

Unitholders have the right to vote with respect to the election of LINN’s directors, certain amendments to LINN’s limited liability company agreement, the merger of LINN or the sale of all or substantially all of its assets and the dissolution of LINN.

Our shareholders are not entitled to vote to elect our board of directors.

Our shareholders will be entitled to vote on certain fundamental matters affecting us, such as certain amendments to our limited liability company agreement, certain mergers of our company, the sale of all or substantially all of our assets and our voluntary dissolution and winding up.

We will submit to a vote of our shareholders any matter submitted by LINN to a vote of its unitholders, including the election of LINN’s directors. We will vote the LINN units that we hold in the same manner as the owners of our shares vote (or refrain from voting) their shares on those matters.

Limited Call Rights

If at any time a person owns more than 90% of the outstanding LINN units, such person may elect to purchase all, but not less than all, of the remaining outstanding units at a price equal to the higher of theIf LINN or any of its affiliates own 80% or more of our shares, LINN has the right, which it may assign to any of its affiliates, to purchase all of our remaining outstanding shares, at a

Index to Financial Statements

LINN Units

LinnCo Shares

current market price (as defined in LINN’s limited liability company agreement) or the highest price paid by such person or any of its affiliates for any LINN units purchased during the 90-day period preceding the date notice was mailed to the LINN unitholders informing them of such election.

purchase price not less than the then-current market price of our shares.

In addition, we may be required to sell our LINN units in the event that a person owns more than 90% of the outstanding LINN units and exercises the call right associated therewith. In such event, we will distribute to the holders of outstanding shares of all classes any cash we receive, net of any income taxes payable by us and after payments to creditors and satisfaction of other obligations, and our shares will be canceled and we will be dissolved.

Listing ExchangeUnits are traded on the NASDAQ Global Select Market under the symbol “LINE.”

We intend to apply to list our shares on the NASDAQ Global Select Market under the symbol “LNCO.”

The voting share(s) will not be listed for trading on any stock exchange.

Index to Financial Statements

SHARES ELIGIBLE FOR FUTURE SALE

Upon completion of the offering, we will have outstanding                  shares. All of the shares sold in the offering will be freely tradable without restriction.

Prior to the offering, there has been no public trading market for our shares. Sales of substantial amounts of shares in the open market following the effective date, unless such shares are subject to vesting restrictions with us or the perception that those sales could occur, could adversely affect prevailing market prices and could impair our ability to raise capital in the future through the sale of our equity securities.lock-up restrictions described above.

Our limited liability company agreement provides that we may issue an unlimited number of common shares and voting shares without a vote of our shareholders. Any issuance of additional common shares would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the dividends to and market price of, shares then outstanding. Please read “Description of Our Shares—Issuance of Additional Shares.”

Index to Financial Statements

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCESCONSIDERATIONS FORNON-U.S. HOLDERS

Scope of Discussion

The following is a discussionsummary of the material U.S. federal income tax consequences relatingconsiderations related to an investment in the shares. This discussion is limited to holders that hold the shares as “capital assets” within the meaningpurchase, ownership and disposition of Section 1221 of the Internal Revenue Code of 1986, as amended (the “Code”). For purposes of this discussion, “holder” means eitherour Class A common stock by a U.S.non-U.S. holder (as defined below) that holds our Class A common stock as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Code, U.S. Treasury regulations, administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service (“IRS”) with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a non-U.S. holder (as defined below) or both, as the context may require.court will agree with such statements and conclusions.

This discussion does not address any aspect of non-income taxation, any state, local or foreign taxation or the effect of any tax treaty. Moreover, this discussionsummary does not address all aspects of the U.S. federal income tax consequencestaxation that may be relevant tonon-U.S. holders in light of their particular circumstancespersonal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal estate or except as specifically discussed below,gift tax laws, any state, local ornon-U.S. tax laws or any tax treaties. This summary also does not address tax considerations applicable to holders whoinvestors that may be subject to special treatment under the U.S. federal income tax laws, such as:

 

banks, thrifts, insurance companies andor other financial institutions;

 

tax-exempt or governmental organizations;

 

partnerships or other pass-throughqualified foreign pension funds (or any entities (or their investors or beneficiaries)all of the interests of which are held by a qualified foreign pension fund);

regulated investment companies and mutual funds;

real estate investment trusts;

 

dealers in securities or traders in stocks and securities, foreign currencies or notional principal contracts;currencies;

 

holders subject to the alternative minimum tax provisions of the Code;

certain expatriates or former long-term residents of the United States;

U.S. holders that have apersons whose functional currency other thanis not the U.S. dollar;

personal holding companies;

 

“controlled foreign corporations,” “passive foreign investment companies” orcompanies,” and corporations that accumulate earnings to avoid U.S. federal income tax;

 

holderstraders in securities that own, or are deemed to own, more than 5%use themark-to-market method of the shares;

holders that received shares as compensation for the performance of services or pursuant to the exercise of options or warrants; or

holders that hold shares as part of a hedge, conversion or constructive sale transaction, straddle, wash sale or other risk reduction transaction or other integrated transaction.

If a partnership (including an entity or other arrangement treated as a partnershipaccounting for U.S. federal income tax purposes) is an ownerpurposes;

persons subject to the alternative minimum tax;

partnerships or other pass-through entities for U.S. federal income tax purposes or holders of shares,interests therein;

persons deemed to sell our Class A common stock under the tax treatmentconstructive sale provisions of the Code;

persons that acquired our Class A common stock through the exercise of employee stock options or otherwise as compensation or through atax-qualified retirement plan;

certain former citizens or long-term residents of the United States; and

persons that hold our Class A common stock as part of a partner will generally depend on the status of the partner, the activities of the partnership and certain determinations made at the partner level. Partners of partnerships that are owners of shares should consult their tax advisors.straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction.

Except as discussed below under “—LINN Partnership Status,” the discussion is not an opinion of counsel.

THIS DISCUSSION IS NOT A SUBSTITUTE FOR AN INDIVIDUAL ANALYSIS OF THE TAX CONSEQUENCES RELATING TO AN INVESTMENT IN THE SHARES. WE URGE YOUPROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT YOUR OWNTHEIR TAX ADVISOR CONCERNINGADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES TO YOU IN LIGHT OF YOUR FACTSTHE PURCHASE, OWNERSHIP AND CIRCUMSTANCES AND ANY CONSEQUENCESDISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, FOREIGNNON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

Index to Financial Statements

LINN Partnership StatusNon-U.S. Holder Defined

Section 7704For purposes of the Code providesthis discussion, a“non-U.S. holder” is a beneficial owner of our Class A common stock that publicly traded partnerships will, as a general rule, be treated as corporations for U.S. federal income tax purposes. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income” within the meaning of Section 7704(d) of the Code. If a publicly traded partnership meets this exception and has not elected to be treated as a corporation, it will be treated as a partnership for U.S. federal income tax purposes.

Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. LINN estimates that less than 5% of its current gross income is not qualifying income; however, this estimate could change from time to time.

Subject to the assumptions, qualifications and limitations set forth below, Baker Botts L.L.P. (“Counsel”) is of the opinion that at least 90% of LINN’s current gross income constitutes qualifying income, that LINN will be treated as a partnership for U.S. federal income tax purposes and that LINN’s principal operating subsidiary, Linn Energy Holdings, LLC (the “Operating Company”), will be disregarded as an entity separate from LINN for U.S. federal income tax purposes.

In providing this opinion, Counsel has examined and is relying upon the truth and accuracy at all relevant times of this prospectus, the registration statement of which this prospectus forms a part, representations made by LINN and such other records and documents as in Counsel’s judgment are necessarypartnership or appropriate to enable Counsel to provide this opinion. Counsel has not, however, undertaken any independent investigation of any factual matter set forth in any of the foregoing.

The representations made by LINN upon which Counsel has relied are:

neither LINN nor the Operating Company has elected or will elect to be treated as a corporation; and

for each taxable year since LINN’s inception, more than 90% of LINN’s gross income will be income that Counsel has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Code.

This opinion is based upon Counsel’s interpretation of the Code, its regulations, court decisions, published positions of the Internal Revenue Service (“IRS”) and other applicable authorities, all as in effect on the date of this prospectus and all of which are subject to change or differing interpretations, possibly with retroactive effect. This opinion is rendered as of the date of this prospectus, and Counsel assumes no obligation to advise us or you of any change in fact, circumstances or law which may alter, affect or modify this opinion. This opinion is not binding on the IRS or a court, and no ruling has been or will be obtained from the IRS regarding any of the matters addressed in this opinion. As a result, no assurance can be given that the IRS will not assert, or that a court will not sustain, a position contrary to the matters addressed in this opinion.

LinnCo U.S. Federal Income Taxation

We have elected to be treated as a corporation for U.S. federal income tax purposes. Thus, we are obligated to pay U.S. federal income tax on our net taxable income. Currently, the maximum regular U.S. federal income tax rate for a corporation is 35%, but we may be subject to a 20% alternative minimum tax on our alternative minimum taxable income to the extent that the alternative minimum tax exceeds our regular income tax.

Although the Code generally provides that a regulated investment company does not pay an entity-level income tax, provided that it distributes all or substantially all of its income, we do not meet the current tests for

Index to Financial Statements

qualification as a regulated investment company under the Code because most or substantially all of our investments will consist of investments in LINN units. The regulated investment company tax rules therefore have no application to us.

Consequences to U.S. Holders

The following is a discussion of the material U.S. federal income tax consequences that will apply to U.S. holders. The term “U.S. holder” means a beneficial owner of shares that, for U.S. federal income tax purposes, is:following:

 

an individual who is a citizen or resident alien of the United States;

 

a corporation (or any other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof ofor the District of Columbia;

 

an estate the income of which is subject to U.S. federal income taxationtax regardless of its source; or

 

a trust if it (1)(i) the administration of which is subject to the primary supervision of a U.S. court within the United States and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (2)(ii) which has made a valid election in effect under applicable U.S. Treasury Regulationsregulations to be treated as a United States person.

Distributions on the Shares

Because we areIf a corporationpartnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes,purposes) holds our Class A common stock, the tax treatment of a holderpartner in the partnership generally will not include its allocable sharedepend upon the status of the partner, upon the activities of the partnership and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our Class A common stock to consult their tax advisors regarding the U.S. federal income gains, lossestax considerations of the purchase, ownership and disposition of our Class A common stock by such partnership.

Distributions

We do not expect to pay any distributions on our Class A common stock in the foreseeable future. However, in the event we do make distributions of cash or deductions in computing the holder’s own taxable income. Distributions paid with respect toother property on our sharesClass A common stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent ofpaid from our current or accumulated earnings and profits, (asas determined forunder U.S. federal income tax purposes). Distributions in excess ofprinciples. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated first as a tax-freenon-taxable return of capital to the extent of the U.S.non-U.S. holder’s tax basis in the sharesour Class A common stock and will reduce (but not below zero) such basis. A distribution in excess of our earnings and profits and the U.S. holder’s tax basis in the shares will be treatedthereafter as capital gain realized onfrom the sale or exchange of such shares.

We estimate that if you ownClass A common stock. See “—Gain on Disposition of Class A Common Stock.” Subject to the shares that you purchase in this offering through December 31, 2015, you will recognize, on a cumulative basis, an amount of taxable dividend income that will be         % or less of the cash dividends paid to you during that period. However, the ratio of taxable dividend income to cash dividends for any single year in that period may be higher or lower. The excess of the cash dividends that you receive over your taxable dividend income during that period will reduce your tax basis in your shares. After December 31, 2015, we anticipate that the ratio of taxable dividend income to cash dividends will increase. These estimates are based upon assumptionswithholding requirements under FATCA (as defined below) and with respect to LINN’s earnings from its operations, the amounteffectively connected dividends, each of those earnings allocatedwhich is discussed below, any distribution made to us,anon-U.S. holder on our income tax liabilities and the amount of the distributions paid to us by LINN. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we and LINN will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable dividend income to cash dividends could be higher or lower than expected, and any differences could be material and could materially affect the value of the shares.

Distributions that are treated as dividends generally will be taxable as ordinary income to U.S. holders but (i) are expected to be treated as “qualified dividend income” that is currently subject to reduced rates of U.S. federal income taxation for non-corporate U.S. holders and (ii) may be eligible for the dividends received deduction available to corporate U.S. holders, in each case provided that certain holding period requirements are met. Qualified dividend income is currently taxable to non-corporate U.S. holders at a maximum U.S. federal income tax rate of 15% for taxable years beginning before January 1, 2013. Thereafter, qualified dividend income will be taxed at ordinary income rates unless further legislative action is taken. The reduced maximum tax rate on dividends will not apply to dividends received to the extent that the U.S. holder elects to treat such dividends as “investment income,” which may be offset by investment expense.

Index to Financial Statements

Certain limitations apply to the availability of the dividends received deduction for corporate holders, including limitations on the aggregate amount of the deduction that may be claimed and limitations based on the holding period of the shares on which the dividend is paid, which holding period may be reduced if the holder engages in risk reduction transactions with respect to its shares.

U.S. holders should consult their own tax advisors regarding the holding period and other requirements that must be satisfied in order to qualify for the reduced maximum tax rate on dividends and the dividends received deduction.

Sale, Exchange or Other Taxable Disposition of Shares

Generally, the sale, exchange or other taxable disposition of shares will result in taxable gain or loss to a U.S. holder equal to the difference between (1) the amount of cash plus the fair market value of any other property received by such U.S. holder in the sale, exchange or other taxable disposition and (2) such U.S. holder’s adjusted tax basis in the shares.Class A U.S. holder’s adjusted tax basis in the shares will generally equal its cost for the shares, decreased (but not below zero) by the amount of any distributions treated as a tax-free return of capital as described above under “—Distributions on the Shares.”

Gain or loss recognized on the sale, exchange or other taxable disposition of shares will generally be capital gain or loss and will be long-term capital gain or loss if the shares are held for more than one year. A reduced tax rate on capital gain generally will apply to long-term capital gain of a non-corporate U.S. holder. There are limitations on the deductibility of capital losses.

Investment by Tax-Exempt Investors and Regulated Investment Companies

A tax-exempt investor will not have unrelated business taxable income attributable to its ownership of shares or to its sale, exchange or other disposition of shares unless its ownership of shares is debt-financed. In general, shares would be debt-financed if the tax-exempt investor incurs debt to acquire shares or otherwise incurs or maintains a debt that would not have been incurred or maintained if those shares had not been acquired.

Distributions that constitute dividends with respect to the shares will result in income that is qualifying income for a regulated investment company or a mutual fund. Furthermore, any gain from the sale, exchange or other disposition of shares will constitute gain from the sale, exchange or other disposition ofcommon stock or securities and will also result in income that is qualifying income for a regulated investment company. Finally, the shares will constitute qualifying assets to regulated investment companies, which generally must own at least 50% in qualifying assets and not more than 25% in certain non-qualifying assets at the end of each quarter, provided such regulated investment companies do not violate certain percentage ownership limitations with respect to the shares.

Backup Withholding and Information Reporting

In general, distributions in respect of the shares, and the proceeds of a sale, exchange or other taxable disposition of the shares, paid to a U.S. holder are subject to information reporting and may be subject to U.S. federal backup withholding unless the U.S. holder (i) is an exempt recipient or (ii) provides us with a correct taxpayer identification number and certifies that it is not subject to backup withholding. Backup withholding is not an additional tax. Any amount withheld from a payment to a U.S. holder under the backup withholding rules is allowable as a credit against such holder’s U.S. federal income tax liability and may entitle such holder to a refund, provided that the required information is timely furnished to the IRS.

Index to Financial Statements

Consequences to Non-U.S. Holders

The following is a discussion of the material U.S. federal income tax consequences that will apply to non-U.S. holders. The term “non-U.S. holder” means a beneficial owner of shares (other than a partnership) who is not a U.S. holder.

Distributions on the Shares

Dividends paid to a non-U.S. holder generally will be subject to withholding of U.S. federal incomewithholding tax at a rate of 30% rate (or such lower rate as may be specified byof the gross amount of the distribution unless an applicable income tax treaty) unlesstreaty provides for a lower rate. To receive the dividendsbenefit of a reduced treaty rate, anon-U.S. holder must provide the applicable withholding agent with an IRSForm W-8BEN or IRSForm W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.

Dividends paid to anon-U.S. holder that are effectively connected with a trade or business carried onconducted by thenon-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment or fixed base of the non-U.S. holder in the United States). A non-U.S. holder that is eligible for a reduced rate of withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for refund with the IRS. Under applicable Treasury Regulations, a non-U.S. holder (including, in the case of certain non-U.S. holders that are entities, the owner or owners of these entities) will be required to satisfy certain certification requirements as set forth on IRS Form W-8BEN (or other applicable form) in order to claim a reduced rate of withholding pursuant to an applicable income tax treaty. Non-U.S. holders should consult their own tax advisors regarding their entitlement to benefits under an applicable income tax treaty and the manner of claiming the benefits of such treaty.

Dividends that are effectively connected with a trade or business carried onmaintained by thenon-U.S. holder in the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment or fixed base of the non-U.S. holder in the United States) generally are not subject to the withholding tax described above but instead are subject to U.S. federal income taxwill be taxed on a net income basis at the rates and in the manner generally applicable graduatedto United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if thenon-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS FormW-8ECI certifying eligibility for exemption. If thenon-U.S. holder is a corporation for U.S. federal income tax rates. A non-U.S. holder must satisfy certain certification requirements, including, if applicable, the furnishing of an IRS Form W-8ECI (or other applicable form), for its effectively connected dividends to be exempt from the withholding tax described above. Dividends that are effectively connected with a corporate non-U.S. holder’s conduct of a trade or business in the United Statespurposes, it may also be subject to an additionala branch profits tax at(at a 30% rate (oror such lower rate as may be specified by an applicable income tax treaty).

To the extent distributions paid on our shares exceed our current and accumulatedits effectively connected earnings and profits such distributions(as adjusted for certain items), which will constitute a return of capital and will reduce the adjusted tax basis in such shares, but not below zero. The amounts of any such distribution in excess of such adjusted tax basis will be treated as gain from the sale of shares and will have the tax consequences described under “—Sale, Exchange or Other Taxableinclude effectively connected dividends.

Gain on Disposition of Shares” below.

Sale, Exchange or Other Taxable Disposition of SharesClass A Common Stock

Subject to the discussiondiscussions below under “—Other Recently Enacted Legislation,Backup Withholding and Information Reporting” and “—Additional Withholding Requirements under FATCA,” anon-U.S. holder generally will not be subject to U.S. federal income or withholding tax on any gain realized on aupon the sale exchange or other taxable disposition of shares,our Class A common stock unless:

 

thenon-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the taxablecalendar year of thatin which the sale or disposition occurs and certain other conditions are met;

 

the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business conducted by thenon-U.S. holder in the United States (and, if arequired by an applicable income tax treaty, applies, the gain is attributable to a permanent establishment or fixed base maintained by thenon-U.S. holder in the United States); or

 

our shares constituteClass A common stock constitutes a “UnitedUnited States real property interest”interest by reason of our beingstatus as a “UnitedUnited States real property holding corporation”corporation (“USRPHC”) for U.S. federal income tax purposes and as a result such gain is treated as effectively connected with a trade or business conducted by thenon-U.S. holder in the “regularly traded” exception (discussed below) does not apply to such non-U.S. holder; orUnited States.

the Anon-U.S. holder does not qualify for an exemption from backup withholding, as discussed in “—Information Reporting and Backup Withholding” below.

Index to Financial Statements

An individual non-U.S. holder described in the first bullet point above will be taxed on his or her gains from the sale, exchange or other taxable disposition of shares at a flat rate of 30% (or such lower rate as may be specified by an applicable income tax treaty), which may be offset by certain U.S. source capital losses of such non-U.S. holder provided that such non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses.

Non-U.S. holders that recognize gain from the sale, exchange or other taxable disposition of shares described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

Anon-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph, the third bullet point above, generally will be taxed on a net income basis at the rates and in the manner generally applicable graduatedto United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If thenon-U.S. holder is a corporation for U.S. federal income tax rates in much the same manner as if such holder were a resident of the United States, andpurposes whose gain is described in the case of corporate non-U.S. holders, thesecond bullet point above, then such gain would also be included in its effectively connected earnings and profits (as adjusted for certain items), which may be subject to a branch profits tax discussed above also may apply.(at a 30% rate or such lower rate as specified by an applicable income tax treaty).

IfGenerally, a non-U.S. holdercorporation is subjecta USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax because ofpurposes. However, as long as our status as a USRPHCClass A common stock is and continues to be “regularly traded on an established securities market” (within the regularly traded exception (discussed below) does not apply to such non-U.S. holder, then, in the case of any disposition of shares by the non-U.S. holder, the purchaser may be required to deduct and withhold a tax equal to 10%meaning of the amount realized on the disposition. Non-U.S. holders subject to U.S. federal income tax will also be subject to certain U.S. filing and reporting requirements. We believeTreasury regulations), only anon-U.S. holder that we are a USRPHC. Nevertheless, such income tax and such withholding will not apply unless such non-U.S. holder’s shares (including shares that are attributed to such holder under applicable attribution rules) represent more than 5% of the total fair market value of all of the sharesactually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or thenon-U.S. holder’s holding period for the Class A common stock, more than 5% of our Class A common stock will be treated as disposing of a U.S. real property interest and will be taxable on gain realized on the disposition of such shares by the non-U.S. holder, assuming that the shares are “regularly traded” on an established securities market within the meaningour Class A common stock as a result of applicable Treasury Regulations, which provide thatour status as a class of interests that isUSRPHC. If our Class A common stock were not considered to be regularly traded on an established securities market, locatedsuch holder (regardless of the percentage of stock owned) would be treated as disposing of a U.S. real property interest and would be subject to U.S. federal income tax on a taxable disposition of our Class A common stock (as described in the United States is consideredpreceding paragraph), and a 15% withholding tax would apply to be regularly traded for any calendar quarter during which it is regularly quoted by brokers or dealers making a market in these interests. We expect to satisfy this regularly traded exception, but this cannot be assured. Prospective investorsthe gross proceeds from such disposition.

Non-U.S. holders should consult their own tax advisors regardingwith respect to the application of the regularly traded exception.foregoing rules to their ownership and disposition of our Class A common stock.

Backup Withholding and Information Reporting and Backup Withholding

In general, backup withholding will apply toAny dividends in respect of the shares paid to anon-U.S. holder unless such non-U.S. holder has provided the required certification that it is not a United States person and the payor does not have actual knowledge (or reason to know) that the non-U.S. holder is a United States person or such non-U.S. holder otherwise establishes an exemption from backup withholding. Dividends paid to a non-U.S. holder generally willmust be exempt from backup withholding if the non-U.S. holder provides a properly executed IRS Form W-8BEN or otherwise establishes an exemption from backup withholding. Generally, information regarding the amount of distributions paid, the name and address of the recipient and the amount, if any, of tax withheld will be reported annually to the IRS and to the recipient even if no tax was required to be withheld.non-U.S. holder. Copies of these information reportsreturns may also be made available under the provisions of an applicable treaty or other agreement to the tax authorities ofin the country in which the

non-U.S. holder resides or is a resident for purposesestablished. Payments of such treaty or agreement.

In general,dividends to anon-U.S. holder generally will not be subject to backup withholding and information reporting will apply toif the paymentnon-U.S. holder establishes an exemption by properly certifying itsnon-U.S. status on an IRSForm W-8BEN or IRSForm W-8BEN-E (or other applicable or successor form).

Payments of the proceeds from thea sale or other disposition of shares by anon-U.S. holder of our Class A common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless such thenon-U.S. holder has provided the required certification that it is not a United States person and the payor does not have actual knowledge (or reason to know) that the holder is a United States person, or such non-U.S. holder otherwise establishes an exemption. In general,exemption by properly certifying itsnon-U.S. status on an IRS FormW-8BEN or IRSForm W-8BEN-E (or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding and information reportinggenerally will not apply to theany payment of the proceeds from thea sale or other disposition of sharesour Class A common stock effected outside the United States by anon-U.S. holder through the non-U.S. office of a broker, except that, in the case of a broker that is a United States person or has certain specified relationships or connections with the United States, information reporting will applybroker. However, unless thesuch broker has documentary evidence in its filesrecords that thenon-U.S. holder is not a United States person and the broker does not have actual knowledge (or reason to know) that the holder is a United States person and certain other conditions are satisfied,met, or thenon-U.S. holder otherwise establishes an exemption. Backup withholdingexemption, information reporting will apply ifto a payment of the sale is subject to information reporting andproceeds of the broker has actual knowledge thatdisposition of our Class A common stock effected outside the non-U.S. holder is a United States person.by such a broker if it has certain relationships within the United States.

Index to Financial Statements

Backup withholding is not an additional tax. Any amount withheld from a payment to a non-U.S. holder underRather, the backup withholding rules is allowable as a credit against such holder’s U.S. federal income tax liability and(if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may entitle such holder to a refund,be obtained, provided that the required information is timely furnished to the IRS.

Non-U.S. holders should consult their own tax advisors regarding the applicationAdditional Withholding Requirements under FATCA

Sections 1471 through 1474 of the information reportingCode, and backup withholding rules to them.

Medicare Tax

Recently enacted legislation requires certain holders who are individuals, estates or trusts to pay a 3.8% unearned income Medicare contribution tax on, among other things, dividends onthe U.S. Treasury regulations and capital gains from the sale or other disposition of shares for taxable years beginning after December 31, 2012. Holders should consult their tax advisors regarding the effect, if any, of this legislation on their ownership and disposition of shares.

Other Recently Enacted Legislation

An additional withholding tax will apply to certain types of payments made after December 31, 2012 (unless certain proposed regulations providing otherwise are finalized, as discussed further below)administrative guidance issued thereunder (“FATCA”), to “foreign financial institutions” and certain other non-U.S. entities. Specifically,impose a 30% withholding tax will be imposed on any dividends paid on orour Class A common stock and on the gross proceeds from the sale or othera disposition of the sharesour Class A common stock (if such disposition occurs after December 31, 2018), in each case if paid to a “foreign financial institution” or a“non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution ornon-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, or to a non-financial foreign entity, unless (i) the foreign financialsuch institution undertakes certain diligence and reporting obligations or (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner. If the payee is a foreign financial institution, it must enterenters into an agreement with the U.S. Treasury requiring, among other things,government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that arenon-U.S. entities with U.S. owners), (ii) in the case of anon-financial foreign entity, such entity certifies that it undertakedoes not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS FormW-8BEN-E), or (iii) the foreign financial institution ornon-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS FormW-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to account holders whose actions prevent it from complying with these reporting and other requirements.different rules. Under certain circumstances, a holder maymight be eligible for refunds or credits of such taxes. The United States Treasury Department and the IRS have recently issued proposed regulations that, if finalized, would provide that the withholding described above would not applyNon-U.S. holders are encouraged to payments made before January 1, 2014 (with respect to dividends on the shares) or January 1, 2015 (with respect to gross proceeds from the sale or other disposition of the shares). The proposed regulations will not be effective until issued in final form, and there can be no assurance as to when those final regulations will be issued or the particular form they might take.

Prospective purchasers of shares should consult their own tax advisors with respect toregarding the tax consequenceseffects of these rules.

FATCA on an investment in our Class A common stock.

Index to Financial Statements
INVESTORS CONSIDERING THE PURCHASE OF OUR CLASS A COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL ESTATE AND GIFT TAX LAWS AND ANY STATE, LOCAL ORNON-U.S. TAX LAWS AND TAX TREATIES.

CERTAIN ERISA CONSIDERATIONS

The following is a summary of materialcertain considerations arising underassociated with the acquisition and holding of shares of Class A common stock by employee benefit plans that are subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), plans, individual retirement accounts and the prohibited transaction provisions ofother arrangements that are subject to Section 4975 the Code or employee benefit plans that are governmental plans (as defined in Section 3(32) of ERISA), certain church plans (as defined in Section 3(33) of ERISA),non-U.S. plans (as described in Section 4(b)(4) of ERISA) or other plans that are not subject to the foregoing but may be relevantsubject to a prospective purchaser of our shares. The discussion does not purportprovisions under any other federal, state, local,non-U.S. or other laws or regulations that are similar to deal with all aspectssuch provisions of ERISA or section 4975 of the Code that may be relevant(collectively, “Similar Laws”), and entities whose underlying assets are considered to particular shareholders in lightinclude “plan assets” of their particular circumstances.any such plan, account or arrangement (each, a “Plan”).

We baseThis summary is based on the foregoing discussion on current provisions of ERISA and the Code existing ERISA(and related regulations and Code regulations, DOL administrative rulings, and reported judicial decisions. Nointerpretations) as of the date of this prospectus. This summary does not purport to be complete, and no assurance can be given that legislative, administrativefuture legislation, court decisions, regulations, rulings or judicial changespronouncements will not affectsignificantly modify the accuracyrequirements summarized below. Any of any statements herein with respectthese changes may be retroactive and may thereby apply to transactions entered into or contemplated prior to the effective date of such changes.their enactment or release. This discussion is general in nature and is not intended to be all inclusive, nor should it be construed as investment or legal advice.

General Fiduciary RequirementsMatters

Each fiduciaryERISA and the Code impose certain duties on persons who are fiduciaries of a pension, profit-sharing or other employee benefit planPlan subject to Title I of ERISA (“ERISAor Section 4975 of the Code (an “ERISA Plan”) should consider carefully whether an investment in our shares is consistent with its fiduciary responsibilities under ERISA. In particular,and prohibit certain transactions involving the ERISA fiduciary responsibilities require an ERISA Plan’s investments to be (1) prudent and in the best interests of the ERISA Plan, its participants and its beneficiaries, (2) diversified in order to minimize the risk of large losses, unless it is clearly prudent not to do so and (3) authorized under the terms of the ERISA Plan’s governing documents (provided the documents are consistent with ERISA). In determining whether an investment in our shares is prudent for purposes of ERISA, the appropriate fiduciaryassets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

In considering an investment in shares of Class A common stock with a portion of the assets of any Plan, a fiduciary should consider the Plan’s particular circumstances and all of the facts and circumstances of the investment and determine whether the acquisition and holding of shares of Class A common stock is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code, or any Similar Law relating to the fiduciary’s duties to the Plan, including, without limitation:

whether the investment is reasonably designed, as a partprudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

whether, in making the ERISA Plan’s portfolio for which the fiduciary has investment, responsibility, to meet the objectives of the ERISA Plan taking into considerationwill satisfy the risk of loss and opportunity for gain (or other return) from the investment, diversification cash flow and funding requirements of the ERISA Plan’s portfolio.

The fiduciary of an individual retirement account (“IRA”) or a governmental plan, church plan or plan that does not cover common-law employees that is not subject to Title I of ERISA (“Non-ERISA Plan”) may only make investments that are authorized by the appropriate governing documents and under applicable state law.

Prohibited Transaction Issues

Fiduciaries of ERISA Plans and fiduciaries or other persons making the investment decision for an IRA or Non-ERISA Plan should consider the application of the prohibited transaction provisionsSection 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

whether the investment is permitted under the terms of the applicable documents governing the Plan;

whether the acquisition or holding of the shares of Class A common stock will constitute a “prohibited transaction” under Section 406 of ERISA or Section 4975 of the Code (please see the discussion under “—Prohibited Transaction Issues” below); and

whether the Plan will be considered to hold, as plan assets, (i) only shares of Class A common stock or (ii) an undivided interest in making their investment decision. Underour underlying assets (please see the prohibited transaction rules, andiscussion under “—Plan Asset Issues” below).

Prohibited Transaction Issues

Section 406 of ERISA Plan, IRA and Non-ERISA Plan are prohibitedSection 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of ERISA, or “disqualified persons,” within the meaning of sectionSection 4975 of the Code, unless an exemption is

available. A “partyparty in interest”interest or “disqualified person” with respect to an ERISA Plan or an IRA or Non-ERISA Plan is subject to (1) an initial 15% excise tax on the amount involved in any prohibited transaction involving the assets of the plan or IRA and (2) an excise tax equal to 100% of the amount involved if any prohibited transaction is not timely corrected. If the disqualified person who engages in the transaction is the individual on behalf of whom an IRA is maintained (or his beneficiary), the IRA will lose its tax-exempt status and its assets will be deemed to have been distributed to such individual in a taxable distribution (and no excise tax will be imposed) on account of the prohibited transaction. In addition, a fiduciary who permits an ERISA Plan to engage in a transaction that the fiduciary knows or should know is anon-exempt prohibited transaction may be liablesubject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan for any loss the ERISA Plan incurs asthat engages in such a result of thenon-exempt prohibited transaction or for any profits earned by the fiduciary in the transaction.

Plan Asset Issues

Certain rules apply in determining whether the fiduciary requirements ofmay be subject to penalties and liabilities under ERISA and the Code. The acquisition and/or holding of shares of Class A common stock by an ERISA Plan with respect to which the issuer, the initial purchaser, or a guarantor is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction provisionsunder Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption.

Because of the foregoing, shares of Class A common stock should not be acquired or held by any person investing “plan assets” of any Plan, unless such acquisition and holding will not constitute anon-exempt prohibited transaction under ERISA and the Code apply to an entity because one or more investors in the equity

Index to Financial Statements

interests in the entity is an ERISA Plan or an IRA or a Non-ERISA similar violation of any applicable Similar Laws.

Plan subject to section 4975Asset Issues

Additionally, a fiduciary of the Code. An ERISAa Plan fiduciary should consider whether the relevance of the fiduciary requirements of ERISA and the prohibited transaction provisions of ERISA and the Code with respectPlan will, by investing in us, be deemed to ERISA’s prohibition on improper delegation of control over or responsibility for “plan assets” and ERISA’s imposition of co-fiduciary liability with respect to who participates in, permits (by action or inaction) the occurrence of or fails to remedy a known breach by another fiduciary.

Regulations of the U.S. Department of Labor (“DOL”) defining “plan assets,” known as the “Plan Asset Regulations,” generally provide that when an ERISA Plan or a Non-ERISA Plan or an IRA acquires a security that is an equity interest in an entity and the security is neither a “publicly offered security” nor a security issued by an investment company registered under the Investment Company Act of 1940, the ERISA or Non-ERISA Plan’s or IRA’s assets include both the equity interest andown an undivided interest in each ofour assets, with the underlying assets of the issuer of such equity interest, unless one or more exceptions specified in the Plan Asset Regulations are satisfied.

For purposesresult that we would become a fiduciary of the Plan Asset Regulations, aand our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor (the “DOL”) regulations provide guidance with respect to whether the assets of an entity in which ERISA Plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets generally would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by ERISA Plans are “publicly offered security” is a security that is “freely transferable,”securities” (as defined in the DOL regulations)—i.e., the equity interests are part of a class of securities that is “widelywidely held” and either (a) is sold to the ERISA Plan as part of an offering of securities to the public pursuant to an effective registration statement under the Securities Act and the class of securities to which such security is a part is registered under the Exchange Act within 120 days after the end of the fiscal year of the issuer during which the offering of such securities to the public has occurred or (b) is part of a class of securities that is registered under Section 12 of the Exchange Act. The Plan Asset Regulations provide that a security is “widely held” only if it is part of a class of securities that is owned by 100 or more investors independent of the issuer and one another. A security will not fail to be “widely held” becauseeach other, are freely transferable, and are either registered under certain provisions of the number of independent investors falls below 100 subsequentfederal securities laws or sold to the initial offering thereof as a result of events beyond the control of the issuer. TheERISA Plan Asset Regulations provide that whether a security is “freely transferable” is a factual question to be determined on the basis of all the relevant facts and circumstances.

We anticipate that our shares to be sold in this offering will meet the criteria of publicly offered securities under the Plan Asset Regulations, although no assurances can be given in this regard. The underwriters expect (although no assurance can be given) that our shares will be (1) held beneficially by more than 100 independent persons at the conclusion of the offering and thus widely held, (2) freely transferable as no restrictions will be imposed on the transfer of our shares and (3) sold as part of a public offering under certain conditions;

(b) the entity is an offering pursuant“operating company” (as defined in the DOL regulations)—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by “benefit plan investors” (as defined in the DOL regulations)—i.e., immediately after the most recent acquisition by an ERISA Plan of any equity interest in the entity, less than 25% of the total value of each class of equity interest (disregarding certain interests held by persons (other than benefit plan investors) with discretionary authority or control over the assets of the entity or who provide investment advice for a fee (direct or indirect) with respect to an effective registration statement under the Securities Act of 1933. As a result, we anticipate that our shares will be timely registered under the Exchange Act.

Governmentalsuch assets, and any affiliates thereof) is held by ERISA Plans, IRAs and certain other Plans (but not including governmental plans, foreign plans and certain church plansplans), and non-U.S. plans, while not subjectentities whose underlying assets are deemed to include plan assets by reason of a Plan’s investment in the entity.

Due to the fiduciary responsibility orcomplexity of these rules and the excise taxes, penalties and liabilities that may be imposed upon persons involved innon-exempt prohibited transaction provisions of ERISA or section 4975 of the Code, may nevertheless be subject to other federal, state, local, non-U.S.transactions, it is particularly important that fiduciaries, or other laws that are substantially similar to the foregoing provisions of ERISA persons considering acquiring and/or the Code (“Similar Laws”).

Careful Consideration of ERISA and Code Issues Is Recommended

The foregoing discussion is not intended as a substitute for careful consideration of issues under ERISA and the Code which may be relevant to a person purchasing ourholding shares with “plan assets.” The ERISA and prohibited transaction provisions and regulations applicable to persons investing “plan assets” are complex and are subject to varying interpretations. Moreover, the effect of such laws and regulations and the potential availability of exemptions thereto will vary with the particular circumstances of each prospective holder and in reviewing this prospectus these matters should be considered.Each fiduciary or other person considering the purchase of our sharesClass A common stock on behalf of, or with the assets of, any ERISA plan, IRA or Non-ERISA Plan, is advised to consult with its legal advisor concerningtheir counsel regarding the matters described above regarding issues underpotential applicability of ERISA, sectionSection 4975 of the Code and any Similar Laws.

IndexLaws to Financial Statements

UNDERWRITING

Barclays Capital Inc.such investment and are acting as representatives of the underwriters and as joint book-running managers of this offering. Under the terms ofwhether an underwriting agreement, which willexemption would be filed as an exhibitapplicable to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective numberacquisition and holding of shares shown opposite its name below:

Underwriter

Number
of Shares

Barclays Capital Inc.  

Total

of Class A common stock. Purchasers of shares of Class A common stock have the exclusive responsibility for ensuring that their acquisition and holding of shares of Class A common stock complies with the fiduciary responsibility rules of ERISA and does not violate the prohibited transaction rules of ERISA, the Code or applicable Similar Laws. The underwriting agreement provides that the underwriters’ obligationsale of shares of Class A common stock to purchase shares depends on the satisfaction of the conditions containeda Plan is in the underwriting agreement including:

the obligation to purchase all of the shares offered hereby (other than those shares coveredno respect a representation by their option to purchase additional shares as described below), ifus or any of the shares are purchased;our affiliates or representatives that such an investment meets all relevant legal requirements with respect to investments by any such Plan or that such investment is appropriate for any such Plan.

the representations and warranties made by us to the underwriters are true;

there is no material change in our business the financial markets; and

we deliver customary closing documents to the underwriters.

Commissions and ExpensesPLAN OF DISTRIBUTION

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay us for the shares.

No ExerciseFull Exercise

Per share

$$

Total

$$

The representatives of the underwriters have advised us that the underwriters propose to offer the shares directly to the public at the public offering price on the cover of this prospectus and to selected dealers, whichselling stockholders may, include the underwriters, at such offering price less a selling concession not in excess of $         per share. After the offering, the representatives may change the offering price and other selling terms. Sales of shares made outside of the United States may be made by affiliates of the underwriters.

The expenses of the offering that are payable by us are estimated to be $         (excluding underwriting discounts and commissions).

Option to Purchase Additional Shares

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of                 shares at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell, more than                 shares in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.

Index to Financial Statements

Lock-Up Agreements

We have agreed that, without the prior written consent of Barclays Capital Inc., we will not directly or indirectly, (1) offer for sale, sell, pledgetransfer or otherwise dispose of (or enter into any transaction or device that is designed to,all of their shares or could be expected to, resultinterests in the dispositionshares on any stock exchange, market or trading facility on which the shares are traded or in private transactions. The selling stockholders may sell their shares of Class A common stock from time to time at the prevailing market price or in privately negotiated transactions.

The selling stockholders may use any one or more of the following methods when disposing of shares or interests therein:

ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

block trades in which the broker-dealer will attempt to sell the shares as agent, but may position and resell a portion of the block as principal to facilitate the transaction;

purchases by any person at any time ina broker-dealer as principal and resale by the future of) any shares (including, without limitation, shares that may be deemed to be beneficially owned by usbroker-dealer for its account;

an exchange distribution in accordance with the rules and regulations of the SEC and shares that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for shares or sell or grant options, rights or warrants with respect to any shares or securities convertible into or exchangeable for shares (other than the sale of the shares to the underwriters in this offering), (2) enter into any swap or other derivative transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the shares, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares or securities convertible, exercisable or exchangeable into shares or any of our other securities (4) publicly disclose the intention to do any of the foregoing for a period of     days after the date of this prospectus.

The     -day restricted period described in the preceding paragraph will be extended if:

during the last 17 days of the     -day restricted period we issue an earnings release or material news or a material event relating to us occurs; orapplicable exchange;

 

prior to the expiration of the     -day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the     -day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by Barclays Capital Inc.

Barclays Capital Inc., in its sole discretion, may release the shares and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release shares and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of shares and other securities for which the release is being requested and market conditions at the time. Barclays Capital Inc. has informed us that it does not presently intend to release any shares or other securities subject to the lock-up agreements.

Offering Price Determination

Prior to this offering, there has been no public market for the shares. The initial public offering price will beprivately negotiated between the representatives and us. In determining the initial public offering price of the shares, the representatives will consider:

estimates of distributions to LINN’s unitholders and dividends to our shareholders;transactions;

 

the history and prospects for the energy industry;in underwritten transactions;

 

LINN’s financial information;

the prevailing securities markets at the time of this offering; and

the recent market prices of, and the demand for, publicly traded shares of companies similar to LINN.

Indemnification

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Index to Financial Statements

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the shares, in accordance with Regulation M under the Exchange Act:

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

Syndicate covering transactions involve purchases of the shares in the open marketeffected after the distribution has been completed in order to cover syndicate short positions.

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the shares originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the shares or preventing or retarding a decline in the market price of the shares. As a result, the price of the shares may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Select Market or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the shares. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus ordate the registration statement of which this prospectus formsis a part has not been approved and/is declared effective by the SEC;

through the writing or endorsedsettlement of options or other hedging transactions, whether through an options exchange or otherwise;

broker-dealers may agree with the selling stockholders to sell a specified number of such shares at a stipulated price per share; and

a combination of any such methods of sale.

The selling stockholders may sell the shares at fixed prices, at prices then prevailing or related to the then current market price or at negotiated prices. The offering price of the shares from time to time will be determined by usthe selling stockholders and, at the time of the determination, may be higher or lower than the market price of our Class A common stock on the NYSE or any underwriterother exchange or market.

The shares may be sold directly or through broker-dealers acting as principal or agent, or pursuant to a distribution by one or more underwriters on a firm commitment or best-efforts basis. The selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Index to Financial Statements

NASDAQ Global Select Market

We intend to apply to list the shares on the NASDAQ Global Select Market under the symbol “LNCO.”stockholders may also enter into hedging transactions with broker-dealers. In connection with that listing application,such transactions, broker-dealers of other financial institutions may engage in short sales of our Class A common stock in the underwriters have undertakencourse of hedging the positions they assume with the selling stockholders. The selling stockholders may also enter into options or other transactions with broker-dealers or other financial institutions which require the delivery to sell the minimum numbersuch broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to the minimum number of beneficial owners necessarythis prospectus (as supplemented or amended to meet the NASDAQ Global Select Market listing requirements.

Passive Market Making

reflect such transaction). In connection with thean underwritten offering, underwriters or agents may receive compensation in the form of discounts, concessions or commissions from the selling stockholders or from purchasers of the offered shares for whom they may act as agents. In addition, underwriters may sell the shares to or through dealers, and those dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. The selling group membersstockholders and any underwriters, dealers or agents participating in a distribution of the shares may engage in passive market making transactions in LinnCo sharesbe deemed to be underwriters within the meaning of the Securities Act, and LINN unitsany profit on the NASDAQ Global Select Market in accordancesale of the shares by the selling stockholders and any commissions received by broker-dealers may be deemed to be underwriting commissions under the Securities Act.

The selling stockholders may agree to indemnify an underwriter, broker-dealer or agent against certain liabilities related to the selling of their shares, including liabilities arising under the Securities Act. Under the

registration rights agreement with Rule 103the selling stockholders, we have agreed to indemnify the selling stockholders against certain liabilities related to the sale of Regulation Mthe Class A common stock, including certain liabilities arising under the Securities Act. Under the registration rights agreement, we have also agreed to pay the costs, expenses and fees of registering the shares of Class A common stock, including the reasonable legal fees of the selling stockholders. All other expenses of issuance and distribution including brokers’ or underwriters’ discounts and commissions, if any, and all transfer taxes and transfer fees relating to the sale or disposition of the selling stockholders will be borne by the selling stockholders.

The selling stockholders are subject to the applicable provisions of the Exchange Act, and the rules and regulations under the Exchange Act, duringincluding Regulation M. This regulation may limit the period before the commencementtiming of offers orpurchases and sales of shares and units and extending through the completion of distribution. A passive market maker must display its bids at a price not in excessany of the highest independent bidshares of the security. However, if all independent bids are lowered below the passive market maker’s bid that bid must be lowered when specified purchase limits are exceeded.

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of shares offered by them.

Stamp Taxes

If you purchase sharesClass A common stock offered in this prospectus you may be required to pay stamp taxes and other chargesby the selling stockholders. The anti-manipulation rules under the laws and practicesExchange Act may apply to sales of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Selling Restrictions

European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”) an offer to the public of any shares which are the subject of the offering contemplated by this Prospectus (the “shares”) may not be made in that Relevant Member State except that an offer to the public in that Relevant Member State of any shares may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:

(a) to legal entities which are qualified investors as defined under the Prospectus Directive;

(b) by the Underwriters to fewer than 100, or, if the Relevant Member State has implemented the relevant provisions of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of Barclays Capital Inc. for any such offer; or

(c) in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of shares shall result in a requirement for LinnCo or any Underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any shares to be offered so as to enable an investor to decide to purchase any shares, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member

Index to Financial Statements

State, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in each Relevant Member State and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

United Kingdom

This prospectusis only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive (“Qualified Investors”) that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This prospectusand its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant persons should not act or rely on this document or any of its contents.

Australia

No prospectusor other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (“Corporations Act”)) in relation to the shareshas been or will be lodged with the Australian Securities & Investments Commission (“ASIC”). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:

(a) you confirm and warrant that you are either:

(i)a “sophisticated investor” under section 708(8)(a) or (b) of the Corporations Act;

(ii)a “sophisticated investor” under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;

(iii)a person associated with the company under section 708(12) of the Corporations Act; or

(iv)a “professional investor” within the meaning of section 708(11)(a) or (b) of the Corporations Act,

market and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and

(b) you warrant and agree that you will not offer anyactivities of the sharesfor resale in Australia within 12 months of those sharesbeing issued unless any such resale offer is exempt fromselling stockholders and its affiliates. Furthermore, Regulation M may restrict the requirement to issue a disclosure document under section 708 of the Corporations Act.

Hong Kong

The sharesmay not be offered or sold in Hong Kong, by means of any document, other than (a) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made under that Ordinance or (b) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies Ordinance (Cap. 32, Laws of Hong Kong) or which do not constitute an offer to the public within the meaning of that Ordinance. No advertisement, invitation or document relating to the sharesmay be issued or may be in the possessionability of any person engaged in the distribution of the shares to engage in market-making activities for the purposeparticular securities being distributed for a period of up to five business days before the distribution. The restrictions may affect the marketability of the issue, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to the shareswhich are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) or any rules made under that Ordinance.

Index to Financial Statements

India

This prospectus has not been and will not be registered as a prospectus with the Registrar of Companies in India or with the Securities and Exchange Board of India. This prospectus or any other material relating to these securities is for information purposes only and may not be circulated or distributed, directly or indirectly, to the public or any members of the public in India and in any event to not more than 50 persons in India. Further, persons into whose possession this prospectus comes are required to inform themselves about and to observe any such restrictions. Each prospective investor is advised to consult its advisors about the particular consequences to it of an investment in these securities. Each prospective investor is also advised that any investment in these securities by it is subject to the regulations prescribed by the Reserve Bank of Indiashares and the Foreign Exchange Management Act and any regulations framed thereunder.

Japan

No securities registration statement (“SRS”) has been filed under Article 4, Paragraph 1ability of the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948, as amended) (“FIEL”) in relation to the shares. The sharesare being offered in a private placement to “qualified institutional investors” (tekikaku-kikan-toshika) under Article 10 of the Cabinet Office Ordinance concerning Definitions provided in Article 2 of the FIEL (the Ministry of Finance Ordinance No. 14, as amended) (“QIIs”), under Article 2, Paragraph 3, Item 2 i of the FIEL. Any QII acquiring the sharesin this offer may not transfer or resell those shares except to other QIIs.

Korea

The sharesmay not be offered, sold and delivered directly or indirectly, or offered or sold to any person for reoffering or resale, directly or indirectly,entity to engage in Korea or to any resident of Korea except pursuant to the applicable laws and regulations of Korea, including the Korea Securities and Exchange Act and the Foreign Exchange Transaction Law and the decrees and regulations thereunder. The shareshave not been registered with the Financial Services Commission of Koreamarket-making activities for public offering in Korea. Furthermore, the sharesmay not be resold to Korean residents unless the purchaser of the sharescomplies with all applicable regulatory requirements (including but not limited to government approval requirements under the Foreign Exchange Transaction Law and its subordinate decrees and regulations) in connection with the purchase of the shares.

Singapore

This prospectushas not been registered as a prospectus withTo the Monetary Authority of Singapore. Accordingly, this prospectusand any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the sharesmay not be circulated or distributed, nor may the sharesbe offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Future Act, Chapter 289 of Singapore (the “SFA”), (ii) to a “relevant person” as defined in Section 275(2) of the SFA, or any person pursuant to Section 275 (1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the sharesare subscribed and purchased under Section 275 of the SFA by a relevant person which is:

(a)a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

(b)a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole whole purpose is to hold investments and each beneficiary is an accredited investor,

Index to Financial Statements

shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable within six months after that corporation or that trust has acquired the shares under Section 275 of the SFA except:

(i)to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA) and in accordance with the conditions, specified in Section 275 of the SFA;

(ii)(in the case of a corporation) where the transfer arises from an offer referred to in Section 275(1A) of the SFA, or (in the case of a trust) where the transfer arises from an offer that is made on terms that such rights or interests are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets;

(iii)where no consideration is or will be given for the transfer; or

(iv)where the transfer is by operation of law.

By acceptingextent required, this prospectus the recipient hereof represents and warrants that he is entitled to receive it in accordance with the restrictions set forth above and agrees to be bound by limitations contained herein. Any failure to comply with these limitations may constitute a violation of law.

Dubai International Financial Centre

This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The securities to which this prospectus relates may be illiquidamended and/or subject to restrictions on their resale. Prospective purchasers of the securities offered should conduct their own due diligence on the securities. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.

FINRA Rules

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have,supplemented from time to time performed,to describe a specific plan of distribution. Instead of selling the shares of Class A common stock under this prospectus, the selling stockholders may sell the shares of Class A common stock in compliance with the provisions of Rule 144 under the Securities Act, if available, or pursuant to other available exemptions from the registration requirements of the Securities Act.

We are required to pay certain fees and mayexpenses incurred by us incident to the registration of the shares. We have agreed to indemnify the selling stockholders against certain losses, claims, damages and liabilities, including liabilities under the Securities Act. Each selling stockholder has in the future perform, various financial advisory and investment banking services for LINN or forturn agreed to indemnify us for which they receivedcertain specified liabilities.

Under the securities laws of some states, if applicable, the securities registered hereby may be sold in those states only through registered or will receive customary fees and expenses.

licensed brokers or dealers. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of us or LINN. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research viewsaddition, in respect ofsome states such securities may not be sold unless they have been registered or instrumentsqualified for sale or an exemption from registration or qualification requirements is available and may atis complied with.

We cannot assure you that the selling stockholders will sell all or any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Affiliates of certain of the underwriters in this offering are lenders under LINN’s Credit Facility and, accordingly, if LINN elects to use the proceeds it receives from LinnCo to repay debt outstanding under its Credit Facility, those lenders would indirectly receive a portion of the net proceeds from this offering.our Class A common stock offered hereby.

Index to Financial Statements

VALIDITY OF THE SHARESLEGAL MATTERS

The validity of the sharesour Class A common stock offered by this prospectus will be passed upon for us and the selling stockholders by Baker BottsVinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the shares offered hereby will be passed upon for the underwriters by Latham  & Watkins LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of Linn Energy, LLC as of December 31, 20112018 and 2010,2017 and for each of the three years in the three-year period ended December 31, 2011, and the balance sheet of Linn Co, LLC as of April 30, 2012,2018 included in this prospectus have been so included herein and in the registration statement in reliance uponon the reportsreport of KPMGPricewaterhouseCoopers LLP, an independent registered public accounting firm, appearing elsewhere herein, and upongiven on the authority of said firm as experts in accountingauditing and auditing.accounting.

The statementfinancial statements of certain oil and natural gas properties contributed by Linn Energy, Inc., which comprise the statements of revenues and direct operating expenses of the assets acquired by Linn Energy, LLC from BP America Production Company for the yeareight months ended August 31, 2017 and for the years ended December 31, 2011, appearing2016 and 2015, included in this prospectus and registration statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and areso included in reliance upon suchon the report (which contains an emphasis of matter paragraph relating to the basis of presentation as described in Note 1 to the financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of suchsaid firm as experts in accountingauditing and auditing.accounting.

Certain estimatesEstimates of our reserves and related future net cash flows related to our properties as of December 31, 2018, included herein and elsewhere in the proved oil and natural gas reserves of Linn Energy, LLC included or incorporated by reference hereinregistration statement were based in part upon an engineeringa reserve report prepared by independent petroleum engineers, DeGolyer and MacNaughton, independent petroleum engineers. TheseMacNaughton. We have included these estimates are included or incorporated by reference herein in reliance on the authority of such firm as an expert in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange CommissionSEC a registration statement onForm S-l regardingS-1 (including the shares.exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our Class A common stock offered hereby. This prospectus is part of, and does not contain all of the information foundset forth in, the registration statement.statement and the exhibits and schedules thereto. For further information regarding us, LINNwith respect to the Class A common stock offered hereby, we refer you to the registration statement and the shares offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules filed undertherewith. Statements contained in this prospectus as to the Securities Act.contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. The SEC maintains a websiteat www.sec.gov. Our registration statement, of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a web site on the Internet athttp://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site and can also be inspected and copied at the officeswebsite.

We are subject to full information requirements of the New York Stock Exchange Inc., 20 Broad Street, New York, New York 10005.

Upon completion of this offering, weAct. We will filefulfill our obligations with or furnishrespect to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintainedsuch requirements by the SEC or obtained from the SEC’s website as provided above. Our website is located atwww..com and will be activated immediately following this offering. We expect to make available ourfiling periodic reports and other information filed with or furnishedthe SEC. We intend to the SEC free of charge throughfurnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

Our website is included in this prospectus as an inactive textual reference only. The information found on our website as soon as reasonably practicable after those reports and other information are electronicallyis not part of this prospectus or any report filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

Index to Financial Statements

FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These statements may include, but are not limited to, statements about Linn Energy, LLC’s:

business strategy;

acquisition strategy;

financial strategy;

drilling locations;

oil, gas and natural gas liquid (“NGL”) reserves;

realized oil, gas and NGL prices;

production volumes;

lease operating expenses, general and administrative expenses and development costs;

future operating results; and

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our and LINN’s expectations, which reflect estimates and assumptions made by our respective management. These estimates and assumptions reflect our and LINN’s best judgment based on currently known market conditions and other factors. Although we believe such estimates to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, management’s assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this prospectus are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors described in this prospectus or any prospectus supplement and in the reports and other information we file with the SEC. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Index to Financial Statements

INDEX TO FINANCIAL STATEMENTS

 

LinnCo, LLC Financial Statements

Page

ROAN RESOURCES, INC.

  

Unaudited Pro Forma Condensed Financial Information

Report of Independent Registered Public Accounting FirmIntroduction

   F-2 

Balance Sheet asUnaudited Pro Forma Condensed Statement of April 30, 2012Operations for the Year Ended December 31, 2018

   F-3 

Notes to Balance SheetUnaudited Pro Forma Condensed Financial Statements

   F-4 

Linn Energy, LLC Pro FormaAudited Historical Financial Statements

  

Pro Forma Condensed Combined StatementReport of Operations for the three months ended March  31, 2012 (Unaudited)Independent Registered Public Accounting Firm

   F-5 

Pro Forma Condensed Combined StatementBalance Sheets as of Operations for the year ended December 31, 2011 (Unaudited)2018 and 2017

   F-6 

Notes to Pro Forma Condensed Combined Financial Statements (Unaudited)of Operations for the Years Ended December  31, 2018, 2017 and 2016

   F-7 

Statements of Changes in Equity for the Years Ended December  31, 2018, 2017 and 2016

F-8

Statements of Cash Flows for the Years Ended December  31, 2018, 2017 and 2016

F-9

Notes to Financial Statements

F-11

Linn Energy, LLCUnaudited Condensed Consolidated Historical Financial Statements

  

Report of Independent Registered Public Accounting Firm

F-14

Consolidated Balance Sheets as of December 31, 2011 and December 31, 2010

F-15

Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009

F-16

Consolidated Statements of Unitholders’ Capital for the years ended December  31, 2011, 2010 and 2009

F-17

Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009

F-18

Notes to Consolidated Financial Statements

F-19

Linn Energy, LLC Interim Financial Statements

Unaudited Condensed Consolidated Balance Sheets as of March  31, 2012 (Unaudited)2019 and December 31, 20112018

   F-57F-42 

Unaudited Condensed Consolidated Statements of Operations for the three months endedThree Months Ended March 31, 20122019 and 2011 (Unaudited)2018

   F-58F-43 

Unaudited Condensed Consolidated StatementStatements of Unitholders’ CapitalChanges in Equity for the three months endedThree Months Ended March 31, 2012 (Unaudited)2019 and 2018

   F-59F-44 

Unaudited Condensed Consolidated Statements of Cash Flows for the three months endedThree Months Ended March 31, 20122019 and 2011 (Unaudited)2018

   F-60F-45 

Notes to Unaudited Condensed Consolidated Financial Statements (Unaudited)

F-46

THE LINN CONTRIBUTED BUSINESS

Audited Statements of Revenues and Direct Operating Expenses

Report of Independent Auditors

   F-61 

Linn Energy, LLC Statements of Revenues and Direct Operating Expenses of the Assets Acquired from BP America Production Company

Report of Independent Auditors

F-77

Statements of Revenues and Direct Operating Expenses for the year ended December 31, 2011 (Audited) and the three months ended March 31, 2012 and 2011 (Unaudited)

   F-78F-62 

Notes to Statements of Revenues and Direct Operating Expenses

   F-79F-63 

Index to Financial Statements

Report of Independent Registered Public Accounting FirmROAN RESOURCES, INC.

The Board of Directors and Shareholder

Linn Co, LLC

We have audited the accompanying balance sheet of Linn Co, LLC as of April 30, 2012. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in that balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Linn Co, LLC as of April 30, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

May 10, 2012

Index to Financial Statements

LINN CO, LLC

BALANCE SHEET

April 30, 2012

ASSETS

  

Cash

  $          1,000  
  

 

 

 

Total assets

  $1,000  
  

 

 

 

EQUITY

  

Voting shares; unlimited shares authorized; 1 share issued and outstanding

  $1,000  

Shares; unlimited shares authorized; 0 shares issued

   —    
  

 

 

 

Total equity

  $1,000  
  

 

 

 

The accompanying notes are an integral part of this financial statement.

Index to Financial Statements

Linn Co, LLC

Notes to Balance Sheet

Note 1—Formation and Ownership

Linn Co, LLC (“LinnCo”) is a Delaware limited liability company formed on April 30, 2012, under the Delaware Limited Liability Company Act. Linn Energy, LLC (“LINN”), an independent oil and natural gas company traded on the NASDAQ Global Select Market under the symbol “LINE,” owns LinnCo’s sole voting share.

Note 2—Capitalization

LinnCo’s authorized capital structure consists of two classes of interests: (1) shares with limited voting rights and (2) voting shares, 100% of which are currently held by LINN. At May 10, 2012, LinnCo’s issued capitalization consisted of $1,000 contributed by LINN in connection with LinnCo’s formation and in exchange for its voting share. Additional classes of equity interests may be approved by the board of directors and the holders of a majority of the common shares and the voting share(s), voting as separate classes.

LinnCo expects to issue shares for cash to the public as discussed in Note 3, using all of the net proceeds to purchase a number of units from LINN equal to the number of LinnCo shares issued and sold. LinnCo’s governing documents require it to maintain a one-to-one ratio between the number of LinnCo shares outstanding and the number of LINN units it owns. When LINN makes distributions on its units, LinnCo will pay a dividend on its shares of the cash LinnCo receives in respect of its LINN units, net of reserves for income taxes payable by LinnCo.

Note 3—Business

LinnCo proposes to file a registration statement with respect to an initial public offering of shares. At no time after LinnCo’s formation and prior to the public offering has LinnCo had or does it expect to have any operations or own any interest in LINN. After the public offering, LinnCo’s sole purpose is to own LINN units and it expects to have no assets or operations other than those related to its interest in LINN.

LINN has agreed to pay, on LinnCo’s behalf, any legal, accounting, tax advisory, financial advisory and engineering fees, printing costs or other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with the public offering of shares or incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, independent auditor fees and registrar and transfer agent fees. In addition, LINN will also agree to indemnify LinnCo for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities.

Note 4—Income Tax

LinnCo is a limited liability company that has elected to be treated as a corporation for federal income tax purposes.

Index to Financial Statements

LINN ENERGY, LLC

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONSFINANCIAL INFORMATION

Three Months Ended March 31, 2012

   LINN
Energy

Historical
  BP
Historical
   Pro Forma
Adjustments
  LINN
Energy

Pro
Forma
 
   (in thousands, except per unit amounts) 

Revenues and other:

      

Oil, natural gas and natural gas liquids sales

  $348,895   $56,882    $—     $405,777  

Gains on oil and natural gas derivatives

   2,031    —       —      2,031  

Marketing revenues

   1,290    —       —      1,290  

Other revenues

   1,874    —       —      1,874  
  

 

 

  

 

 

   

 

 

  

 

 

 
   354,090    56,882     —      410,972  
  

 

 

  

 

 

   

 

 

  

 

 

 

Expenses:

      

Lease operating expenses

   71,636    20,129     —      91,765  

Transportation expenses

   10,562    —       —      10,562  

Marketing expenses

   692    6,188     —      6,880  

General and administrative expenses

   43,321    —       —      43,321  

Exploration costs

   410    —       —      410  

Bad debt expenses

   16    —       —      16  

Depreciation, depletion and amortization

   117,276    —       16,306(a)   133,924  
      342(b)  

Taxes, other than income taxes

   25,195    4,995     —      30,190  

Losses on sale of assets and other, net

   1,478    —       —      1,478  
  

 

 

  

 

 

   

 

 

  

 

 

 
   270,586    31,312     16,648    318,546  
  

 

 

  

 

 

   

 

 

  

 

 

 

Other income and (expenses):

      

Interest expense, net of amounts capitalized

   (77,519  —       (18,436)(c)   (96,906
      (951)(d)  

Other, net

   (3,269  —       —      (3,269
  

 

 

  

 

 

   

 

 

  

 

 

 
   (80,788  —       (19,387  (100,175
  

 

 

  

 

 

   

 

 

  

 

 

 

Income (loss) before income taxes

   2,716    25,570     (36,035  (7,749

Income tax expense

   (8,918  —       —  (e)   (8,918
  

 

 

  

 

 

   

 

 

  

 

 

 

Net income (loss)

  $(6,202 $25,570    $(36,035 $(16,667
  

 

 

  

 

 

   

 

 

  

 

 

 

Net income (loss) per unit:

      

Basic

  $(0.04    $(0.09
  

 

 

     

 

 

 

Diluted

  $(0.04    $(0.09
  

 

 

     

 

 

 

Weighted average units outstanding:

      

Basic

   193,256       193,256  
  

 

 

     

 

 

 

Diluted

   193,256       193,256  
  

 

 

     

 

 

 

The accompanying notesOn September 24, 2018, a series of transactions were executed that resulted in Linn Energy Holdings, LLC (“LEH”) and Linn Operating, LLC (“LOI”, and together with LEH, “Linn”) and Citizen Energy II, LLC (“Citizen”) contributing their equity interest in Roan Resources LLC (“Roan LLC”) to two new subsidiaries that are an integral partwholly owned by Roan Resources, Inc. (“Roan Inc.”) in exchange for equity interest in Roan Inc. (the “Reorganization”). Following the Reorganization, Roan Inc. became the successor of these pro forma condensed combined statementsLinn in accordance withRule 15d-5 of operations.

Index to Financial Statements

LINN ENERGY, LLC

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Year Ended December 31, 2011

   LINN
Energy

Historical
  BP
Historical
   2011
Acquisitions
Historical
   Pro Forma
Adjustments
  LINN
Energy

Pro Forma
 
   (in thousands, except per unit amounts) 

Revenues and other:

        

Oil, natural gas and natural gas liquids sales

  $1,162,037   $290,240    $197,424    $—     $1,649,701  

Gains on oil and natural gas derivatives

   449,940    —       —       —      449,940  

Marketing revenues

   5,868    —       —       —      5,868  

Other revenues

   4,609    —       —       —      4,609  
  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 
   1,622,454    290,240     197,424     —      2,110,118  
  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Expenses:

        

Lease operating expenses

   232,619    80,493     36,725     —      349,837  

Transportation expenses

   28,358    —       —       —      28,358  

Marketing expenses

   3,681    37,675     —       —      41,356  

General and administrative expenses

   133,272    —       —       —      133,272  

Exploration costs

   2,390    —       —       —      2,390  

Bad debt expenses

   (22  —       —       —      (22

Depreciation, depletion and amortization

   334,084    —       —       100,618(a)   436,786  
        2,084(b)  

Taxes, other than income taxes

   78,522    22,997     12,750     —      114,269  

Losses on sale of assets and other, net

   3,516    —       —       —      3,516  
  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 
   816,420    141,165     49,475     102,702    1,109,762  
  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Other income and (expenses):

        

Loss on extinguishment of debt

   (94,612  —       —       —      (94,612

Interest expense, net of amounts capitalized

   (259,725  —       —       (95,226)(c)   (359,547
        (4,596)(d)  

Other, net

   (7,792  —       —       —      (7,792
  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 
   (362,129  —       —       (99,822  (461,951
  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Income before income taxes

   443,905    149,075     147,949     (202,524  538,405  

Income tax expense

   (5,466  —       —       —  (e)   (5,466
  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Net income

  $438,439   $149,075    $147,949    $(202,524 $532,939  
  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Net income per unit:

        

Basic

  $2.52        $3.04  
  

 

 

       

 

 

 

Diluted

  $2.51        $3.03  
  

 

 

       

 

 

 

Weighted average units outstanding:

        

Basic

   172,044         173,728  
  

 

 

       

 

 

 

Diluted

   172,729         174,453  
  

 

 

       

 

 

 

The accompanying notes are an integral partthe Securities Exchange Act of these pro forma condensed combined statements of operations.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED STATEMENTS OF OPERATIONS

Note 1—Basis of Presentation1934.

The unaudited pro forma condensed combined statement of operations for the three months ended March 31, 2012, is derived from:

the historical consolidated financial statements of LINN Energy; and

the historical statements of revenues and direct operating expenses of certain oil and natural gas properties acquired from BP America Production Company (“BP” and the properties, the “BP Properties”).

The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2011, is derived from:

2018 was based on the historical consolidated financial statements of LINN Energy;

the historical statements of revenues and direct operating expenses of certain oil and natural gas properties acquired from BP;

the historical statements of revenues and direct operating expenses of certain oil and natural gas properties acquired from Plains Exploration & Production Company (“Plains” and the properties, the “Plains Properties”);

the historical statements of revenues and direct operating expenses of certain oil and natural gas properties acquired from Panther Energy Company, LLC and Red Willow Mid-Continent, LLC (collectively referred to as “Panther” and the properties, the “Panther Properties”);

the historical statements of revenues and direct operating expenses of certain oil and natural gas properties acquired from SandRidge Exploration and Production, LLC (“SandRidge” and the properties, the “SandRidge Properties”); and

the historical statements of revenues and direct operating expenses of certain oil and natural gas properties acquired from an affiliate of Concho Resources Inc. (“Concho” and the properties, the “Concho Properties” and together with the Plains Properties, Panther Properties and the SandRidge Properties, the “2011 Acquisitions Properties”).

The unaudited pro forma condensed combined statementsaudited statement of operations give effect to the acquisition from BP as if it had been completed as of January 1, 2011, and the acquisitions from Plains, Panther, SandRidge and Concho as if they had been completed as of January 1, 2010. The transactions and the related adjustments are described in the accompanying notes. In the opinion of Company management, all adjustments have been made that are necessary to present fairly, in accordance with Regulation S-X, the pro forma condensed combined statements of operations.

The unaudited pro forma condensed combined statements of operations are presented for illustrative purposes only, and do not purport to be indicative of the results of operations that would actually have occurred if the transactions described had occurred as presented in such statements or that may be obtained in the future. In addition, future results may vary significantly from those reflected in such statements due to factors described in “Risk Factors” included in the Company’s Annual Report on Form 10-KRoan Inc. for the year ended December 31, 2011,2018 and elsewhere inincludes pro forma adjustments to give effect to the Company’s reports and filings with the Securities and Exchange Commission (“SEC”).Reorganization as if it had occurred on January 1, 2018.

TheThis unaudited pro forma condensed combined statementsstatement of operations for the year ended December 31, 2018 is provided for illustrative purposes only and is not indicative of the results that actually would have occurred had the transactions been in effect on the dates or for the periods indicated, or of results that may occur in the future. This unaudited pro forma condensed financial statement should be read in conjunction with our historical financial statements.

Roan Resources, Inc.

Unaudited Pro Forma Condensed Statement of Operations

Year Ending December 31, 2018

   Roan Inc.
Historical
  Reorganization
Adjustments
  Roan Inc.
Pro Forma
 
   (in thousands, except earnings per share data) 

Revenues

    

Oil sales

  $275,239  $—    $275,239 

Natural gas sales

   46,966   —     46,966 

Natural gas sales – Affiliates

   29,090   —     29,090 

Natural gas liquids sales

   51,467   —     51,467 

Natural gas liquids sales – Affiliates

   37,005   —     37,005 

Gain on derivative contracts

   78,054   —     78,054 
  

 

 

  

 

 

  

 

 

 

Total revenues

   517,821   —     517,821 

Operating expenses

    

Production expenses

   47,600   —     47,600 

Production taxes

   17,579   —     17,579 

Exploration expenses

   43,303   —     43,303 

Depreciation, depletion and amortization

   123,922   —     123,922 

General and administrative

   60,874   (4,577) (a)   56,297 
  

 

 

  

 

 

  

 

 

 

Total operating expenses

   293,278   (4,577  288,701 
  

 

 

  

 

 

  

 

 

 

Total operating income

   224,543   4,577   229,120 

Other income (expense)

    

Interest expense

   (8,352  —     (8,352
  

 

 

  

 

 

  

 

 

 

Income before income taxes

   216,191   4,577   220,768 
    (304,455) (b)  

Income tax expense

   356,862   3,889  (c)   56,296 
  

 

 

  

 

 

  

 

 

 

Net (loss) income

  $(140,671 $(303,767 $164,472 
  

 

 

  

 

 

  

 

 

 

Earnings (loss) per share:

    

Basic

  $(0.92  $1.08 
  

 

 

   

 

 

 

Diluted

  $(0.92  $1.08 
  

 

 

   

 

 

 

Weighted average number of shares outstanding:

    

Basic

   152,232   308  (d)   152,540 
  

 

 

  

 

 

  

 

 

 

Diluted

   152,232   308  (d)   152,540 
  

 

 

  

 

 

  

 

 

 

ROAN RESOURCES, INC.

NOTES TO PRO FORMA CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

1.

Basis of Presentation

Roan Inc. was incorporated in September 2018 to serve as a holding company and, prior to the Company’sReorganization, had no previous operations, assets or liabilities. The historical consolidatedfinancial information is derived from the historical financial statements and the notes thereto included in its Annual Report on

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED STATEMENTS OF OPERATIONS—Continued

Form 10-Kof Roan Inc. The unaudited pro forma condensed statement of operations for the year ended December 31, 2011.2018 assumes that the Reorganization occurred on January 1, 2018. The pro forma statements should also be read in conjunction with the historical statements of revenues and direct operating expenses for the BP Properties and the notes thereto filed elsewhere in this prospectus.

Note 2—Acquisition Dates

The results of operations of the BP Properties and the 2011 Acquisitions Properties have been included in the historical financial statements of the Company since their acquisition dates.

The acquisition of BP Properties was completed on March 30, 2012, with an effective date of January 1, 2012, for total consideration of approximately $1.17 billion.

The acquisition of Plains Properties was completed on December 15, 2011, with an effective date of November 1, 2011, for total consideration of approximately $555 million.

The acquisition of Panther Properties was completed on June 1, 2011, with an effective date of January 1, 2011, for total consideration of approximately $223 million.

The acquisition of SandRidge Properties was completed on April 1, 2011, with the same effective date, for total consideration of approximately $201 million.

The acquisition of Concho Properties was completed on March 31, 2011, with an effective date of March 1, 2011, for total consideration of approximately $194 million.

Note 3—Preliminary Acquisition Accounting

The acquisitions are accounted for under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred. The initial accounting for the acquisition of the BP Properties is not complete and adjustments to estimated amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED STATEMENTS OF OPERATIONS—Continued

The following presents the values assigned to the net assets acquired from BP as of the acquisition date (in thousands):

Assets:

  

Current

  $7,154  

Other property and equipment

   207,735  

Oil and natural gas properties

   979,336  
  

 

 

 

Total assets acquired

  $1,194,225  
  

 

 

 

Liabilities:

  

Current

  $8,823  

Asset retirement obligations

   18,437  
  

 

 

 

Total liabilities assumed

  $27,260  
  

 

 

 

Net assets acquired

  $1,166,965  
  

 

 

 

Current assets include receivables and inventory. Current liabilities include payables, ad valorem taxes payable and environmental liabilities.

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observablehave been adjusted in the market and therefore represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

Note 4—Pro Forma Adjustments

The Company’s historical results of operations include the results of properties acquired since the acquisition dates. The pro forma statements of operations include adjustments to reflect the acquisition from BP as if it had been completed as of January 1, 2011, and the acquisitions from Plains, Panther, SandRidge and Concho as if they had been completed as of January 1, 2010. The unaudited pro forma condensed combinedfinancial statements to give effect to events that are (1) directly attributable to the Reorganization, (2) factually supportable and (3) with respect to the statements of operations, expected to have been adjusted to:a continuing impact on the results.

This unaudited pro forma condensed financial statement is provided for illustrative purposes only and may or may not provide an indication of results in the future.

2.

Pro Forma Adjustments

The following adjustments were made in the preparation of the unaudited pro forma condensed financial statements.

 

(a)record incremental depreciation, depletion and amortization expense, using

Adjustment to remove the units-of-production method, related to oil and natural gas properties acquired as follows:non-recurring transaction costs incurred by Roan Inc. associated with the Reorganization.

for the period from January 1 through March 30, 2012, and for the year ended December 31, 2011, $16 million and $65 million, respectively, related to the BP Properties

for the period from January 1 through December 15, 2011, $23 million related to the Plains Properties

for the period from January 1 through June 1, 2011, $7 million related to the Panther Properties

for the period from January 1 through April 1, 2011, $2 million related to the SandRidge Properties

for the period from January 1 through March 31, 2011, $3 million related to the Concho Properties

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED STATEMENTS OF OPERATIONS—Continued

 

(b)record accretion

Reflects an adjustment to reverse the income tax expense related to asset retirement obligations on oil and natural gas properties acquired as follows:

for the period from January 1 through March 30, 2012, and for the year ended December 31, 2011, $342,000 and $1 million, respectively, related to the BP Properties

for the period from January 1 through December 15, 2011, $520,000 related to the Plains Properties

for the period from January 1 through June 1, 2011, $26,000 related to the Panther Properties

for the period from January 1 through April 1, 2011, $128,000 related to the SandRidge Properties

for the period from January 1 through March 31, 2011, $3,000 related to the Concho Properties

(c)record interest expense as follows:

incremental debt of approximately $1.17 billion incurred to fund the estimated closing price for the BP Properties; the assumed interest rate was 6.25%

incremental debt of approximately $544 million incurred to fund the purchase price of the Plains Properties; the assumed interest rate was 2.9%

incremental debt of approximately $223 million incurred to fund the purchase price of the Panther Properties; the assumed interest rate was 6.5%

A 1/8 percentage change in the assumed interest rate would result in an adjustment to pro forma net income (loss) as follows:

  Three Months
Ended

March  31,
2012
  Year Ended
December 31,
2011
 
  (in thousands) 

BP Properties

 $369   $1,475  

Plains Properties

  —      688  

Panther Properties

  —      141  
 

 

 

  

 

 

 
 $369   $2,304  
 

 

 

  

 

 

 

(d)record incremental amortization of deferred financing fees associated with debt incurred to fund the purchase priceinitial deferred tax liability recognized as a result of the BP PropertiesReorganization. Roan Inc. is taxable as a corporation under the Internal Revenue Code of 1986, as amended, and the Panther Properties

(e)The Companyas a result, is subject to federal, state and local income taxes. Roan LLC was treated as a partnershipflow-through entity for federal and state income tax purposes. The Company subsidiaries that acquiredAs a result, the Properties are also treated as partnershipsnet taxable income or loss of Roan LLC and any related tax credits, for federal and state income tax purposes.purposes, were deemed to pass to the members. Accordingly, no recognitiontax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of the members. The initial recording of the deferred tax liability has been given to federal and state income taxesreflected in the historical financial statements, but is not included in the accompanying unaudited pro forma condensed combined statementsstatement of operations.operations due to itsnon-recurring nature.

The pro forma statements of operations also include an adjustment to the weighted average units outstanding to reflect units issued to fund the purchase price of the SandRidge Properties and the Concho Properties.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED STATEMENTS OF OPERATIONS—Continued

Note 5—Supplemental Oil and Natural Gas Reserve Information

The following tables set forth certain unaudited pro forma information concerning LINN Energy’s proved oil, natural gas and natural gas liquids (“NGL”) reserves for the year ended December 31, 2011, giving effect to the Properties acquired from BP as if they had occurred on January 1, 2011. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development costs. The following reserve data represent estimates only and should not be construed as being precise.

   Year Ended December 31, 2011 
   LINN
Energy
Historical
  BP
Historical
  LINN
Energy

Pro
Forma
 
   Natural Gas (Bcf) 

Proved developed and undeveloped reserves:

    

Beginning of year

   1,233    472    1,705  

Revisions of previous estimates

   (71  7    (64

Purchase of minerals in place

   337    —      337  

Extension and discoveries

   240    —      240  

Production

   (64  (29  (93
  

 

 

  

 

 

  

 

 

 

End of year

   1,675    450    2,125  
  

 

 

  

 

 

  

 

 

 

Proved developed reserves:

    

Beginning of year

   805    472    1,277  

End of year

   998    450    1,448  

Proved undeveloped reserves:

    

Beginning of year

   428    —      428  

End of year

   677    —      677  

   Year Ended December 31, 2011 
   LINN
Energy
Historical
  BP
Historical
  LINN
Energy

Pro
Forma
 
   Oil and NGL (MMBbls) 

Proved developed and undeveloped reserves:

    

Beginning of year

   227.3    46.7    274.0  

Revisions of previous estimates

   (8.3  0.8    (7.5

Purchase of minerals in place

   40.3    —      40.3  

Extension and discoveries

   34.9    —      34.9  

Production

   (11.7  (3.1  (14.8
  

 

 

  

 

 

  

 

 

 

End of year

   282.5    44.4    326.9  
  

 

 

  

 

 

  

 

 

 

Proved developed reserves:

    

Beginning of year

   142.9    46.7    189.6  

End of year

   172.6    44.4    217.0  

Proved undeveloped reserves:

    

Beginning of year

   84.4    —      84.4  

End of year

   109.9    —      109.9  

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED STATEMENTS OF OPERATIONS—Continued

   Year Ended December 31, 2011 
   LINN
Energy
Historical
  BP
Historical
  LINN
Energy

Pro
Forma
 
   Total (Bcfe) 

Proved developed and undeveloped reserves:

    

Beginning of year

   2,597    752    3,349  

Revisions of previous estimates

   (121  13    (108

Purchase of minerals in place

   579    —      579  

Extension and discoveries

   450    —      450  

Production

   (135  (48  (183
  

 

 

  

 

 

  

 

 

 

End of year

   3,370    717    4,087  
  

 

 

  

 

 

  

 

 

 

Proved developed reserves:

    

Beginning of year

   1,662    752    2,414  

End of year

   2,034    717    2,751  

Proved undeveloped reserves:

    

Beginning of year

   935    —      935  

End of year

   1,336    —      1,336  

Summarized in the following table is information for the standardized measure of discounted cash flows relating to proved reserves as of December 31, 2011, giving effect to the BP Properties. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to state income taxes in Texas; however, these amounts are immaterial. The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. For a discussion of the assumptions used in preparing the information presented, refer to the Company’s financial statements for the fiscal year ended December 31, 2011, as well as to the historical statements of revenues and direct operating expenses of the BP Properties included elsewhere in this prospectus.

   December 31, 2011 
   LINN Energy
Historical
  BP
Historical
  LINN Energy
Pro Forma
 
   (in thousands) 

Future estimated revenues

  $29,319,369   $3,892,894   $33,212,263  

Future estimated production costs

   (9,464,319  (1,740,911  (11,205,230

Future estimated development costs

   (2,848,497  (34,753  (2,883,250
  

 

 

  

 

 

  

 

 

 

Future net cash flows

   17,006,553    2,117,230    19,123,783  

10% annual discount for estimated timing of cash flows

   (10,391,693  (1,138,761  (11,530,454
  

 

 

  

 

 

  

 

 

 

Standardized measure of discounted future net cash flows

  $6,614,860   $978,469   $7,593,329  
  

 

 

  

 

 

  

 

 

 

Representative NYMEX prices:(1)

    

Natural gas (MMBtu)

  $4.12    

Oil (Bbl)

  $95.84    

 

(1)(c)

In accordance with SEC regulations, reserves atAdjustment to reflect income tax expense based on the statutory tax rate of 25.5% to prospective periods. As there was no tax provision in the historical financial statements of Roan LLC, it was deemed appropriate to use the statutory tax rate as of December 31, 2011, were estimated using2018 for purposes of calculating the average price duringincome tax expense for the 12-month period determined as an unweighted averagefrom January 1, 2018 through September 24, 2018, the date of the first-day-of-the-month price forReorganization.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED STATEMENTS OF OPERATIONS—Continued

 

(d)each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

The price used to estimate reserves is held constant overpro forma weighted average number of shares outstanding reflects the lifeweighted average number of shares of common stock we would have had outstanding if the reserves.Reorganization had occurred on January 1, 2018.

The following table summarizes the principal sources

Report of change inIndependent Registered Public Accounting Firm

To the standardized measure of discounted future net cash flows:

   Year Ended December 31, 2011 
   LINN
Energy
Historical
  BP
Historical
  LINN
Energy

Pro Forma
 
   (in thousands) 

Sales and transfers of oil, natural gas and NGL produced during the period

  $(822,602 $(149,075 $(971,677

Changes in estimated future development costs

   27,236    (59  27,177  

Net change in sales and transfer prices and production costs related to future production

   784,308    94,698    879,006  

Purchase of minerals in place

   1,452,169    —      1,452,169  

Extensions, discoveries, and improved recovery

   552,704    —      552,704  

Previously estimated development costs incurred during the period

   306,827    —      306,827  

Net change due to revisions in quantity estimates

   (292,343  19,811    (272,532

Accretion of discount

   422,353    106,219    528,572  

Changes in production rates and other

   (39,324  (155,318  (194,642
  

 

 

  

 

 

  

 

 

 
  $2,391,328   $(83,724 $2,307,604  
  

 

 

  

 

 

  

 

 

 

It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and UnitholdersStockholders of Roan Resources, Inc.

Linn Energy, LLC:Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Linn Energy, LLCRoan Resources, Inc. and its subsidiaries (the “Company”) as of December 31, 20112018 and 2010,2017, and the related consolidated statements of operations, unitholders’ capital,of changes in equity and of cash flows for each of the three years in the three-year period ended December 31, 2011. 2018, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for revenue from contracts with customers in 2018.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe Company’s consolidated financial statements based on our audits.

We conducted our audits in accordanceare a public accounting firm registered with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit includesof its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.presentation of the consolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Linn Energy, LLC and subsidiaries/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

April 1, 2019

We have served as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Linn Energy, LLC’s internal control over financial reporting as of December 31, 2011, based on criteria established inInternal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2012, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.auditor since 2016.

/s/ KPMG LLP

Houston, Texas

February 23, 2012, except for Note 16, as to which the date is May 8, 2012

Index to Financial Statements

LINN ENERGY, LLCRoan Resources, Inc.

CONSOLIDATED BALANCE SHEETSConsolidated Balance Sheets

 

   December 31, 
   2011  2010 
   

(in thousands,

except unit amounts)

 

ASSETS

  

Current assets:

   

Cash and cash equivalents

  $1,114   $236,001  

Accounts receivable—trade, net

   284,565    184,624  

Derivative instruments

   255,063    234,675  

Other current assets

   80,734    55,609  
  

 

 

  

 

 

 

Total current assets

   621,476    710,909  
  

 

 

  

 

 

 

Noncurrent assets:

   

Oil and natural gas properties (successful efforts method)

   7,835,650    5,664,503  

Less accumulated depletion and amortization

   (1,033,617  (719,035
  

 

 

  

 

 

 
   6,802,033    4,945,468  

Other property and equipment

   197,235    139,903  

Less accumulated depreciation

   (48,024  (35,151
  

 

 

  

 

 

 
   149,211    104,752  

Derivative instruments

   321,840    56,895  

Other noncurrent assets

   105,577    115,124  
  

 

 

  

 

 

 
   427,417    172,019  
  

 

 

  

 

 

 

Total noncurrent assets

   7,378,661    5,222,239  
  

 

 

  

 

 

 

Total assets

  $8,000,137   $5,933,148  
  

 

 

  

 

 

 

LIABILITIES AND UNITHOLDERS’ CAPITAL

   

Current liabilities:

   

Accounts payable and accrued expenses

  $403,450   $219,830  

Derivative instruments

   14,060    12,839  

Other accrued liabilities

   75,898    82,439  
  

 

 

  

 

 

 

Total current liabilities

   493,408    315,108  
  

 

 

  

 

 

 

Noncurrent liabilities:

   

Credit facility

   940,000    —    

Senior notes, net

   3,053,657    2,742,902  

Derivative instruments

   3,503    39,797  

Other noncurrent liabilities

   80,659    47,125  
  

 

 

  

 

 

 

Total noncurrent liabilities

   4,077,819    2,829,824  
  

 

 

  

 

 

 

Commitments and contingencies (Note 11)

   

Unitholders’ capital:

   

177,364,558 units and 159,009,795 units issued and outstanding at December 31, 2011, and December 31, 2010, respectively

   2,751,354    2,549,099  

Accumulated income

   677,556    239,117  
  

 

 

  

 

 

 
   3,428,910    2,788,216  
  

 

 

  

 

 

 

Total liabilities and unitholders’ capital

  $8,000,137   $5,933,148  
  

 

 

  

 

 

 
   December 31, 
   2018  2017 
   (in thousands, except par value
and share data)
 

ASSETS

   

Current assets

   

Cash and cash equivalents

  $6,883  $1,471 

Accounts receivable

   

Oil, natural gas and natural gas liquid sales

   55,564   74,527 

Affiliates

   9,669   4,695 

Joint interest owners and other, net

   133,387   320 

Prepaid drilling advances

   28,977   —   

Derivative contracts

   82,180   152 

Prepaid expenses

   2,644   651 

Other current assets

   4,011   279 
  

 

 

  

 

 

 

Total current assets

   323,315   82,095 

Noncurrent assets

   

Oil and natural gas properties, successful efforts method

   2,628,333   1,876,951 

Accumulated depreciation, depletion, amortization and impairment

   (230,836  (78,307
  

 

 

  

 

 

 

Oil and natural gas properties, net

   2,397,497   1,798,644 

Derivative contracts

   20,638   996 

Other

   7,659   3,857 
  

 

 

  

 

 

 

Total assets

  $2,749,109  $1,885,592 
  

 

 

  

 

 

 

LIABILITIES AND EQUITY

   

Current liabilities

   

Accounts payable

  $49,746  $—   

Accrued liabilities

   176,494   10,245 

Accounts payable and accrued liabilities – Affiliates

   8,577   183,820 

Revenue payable

   97,963   —   

Drilling advances

   31,058   —   

Derivative contracts

   845   9,279 

Asset retirement obligations

   790   —   
  

 

 

  

 

 

 

Total current liabilities

   365,473   203,344 

Noncurrent liabilities

   

Long-term debt

   514,639   85,339 

Deferred tax liabilities, net

   356,862   —   

Asset retirement obligations

   16,058   10,769 

Derivative contracts

   141   1,371 

Other

   902   —   
  

 

 

  

 

 

 

Total liabilities

   1,254,075   300,823 

Commitments and contingencies (Note 14)

   

Equity

   

Common stock, $0.001 par value; 800,000,000 shares authorized; 152,539,532 shares issued and outstanding at December 31, 2018

   153   —   

Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at December 31, 2018

   —     —   

Additionalpaid-in capital

   1,646,401   —   

Accumulated deficit

   (151,520  —   

Members’ equity

   —     1,584,769 
  

 

 

  

 

 

 

Total equity

   1,495,034   1,584,769 
  

 

 

  

 

 

 

Total liabilities and equity

  $2,749,109  $1,885,592 
  

 

 

  

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

Index to Financial Statements
F-6


LINN ENERGY, LLCRoan Resources, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONSConsolidated Statements of Operations

 

  Year Ended December 31, 
        2011              2010              2009       
  (in thousands, except per unit amounts) 

Revenues and other:

   

Oil, natural gas and natural gas liquids sales

 $1,162,037   $690,054   $408,219  

Gains (losses) on oil and natural gas derivatives

  449,940    75,211    (141,374

Marketing revenues

  5,868    3,966    4,380  

Other revenues

  4,609    3,049    1,924  
 

 

 

  

 

 

  

 

 

 
  1,622,454    772,280    273,149  
 

 

 

  

 

 

  

 

 

 

Expenses:

   

Lease operating expenses

  232,619    158,382    132,647  

Transportation expenses

  28,358    19,594    18,202  

Marketing expenses

  3,681    2,716    2,154  

General and administrative expenses

  133,272    99,078    86,134  

Exploration costs

  2,390    5,168    7,169  

Bad debt expenses

  (22  (46  401  

Depreciation, depletion and amortization

  334,084    238,532    201,782  

Impairment of long-lived assets

  —      38,600    —    

Taxes, other than income taxes

  78,522    45,182    27,605  

(Gains) losses on sale of assets and other, net

  3,516    6,536    (24,598
 

 

 

  

 

 

  

 

 

 
  816,420    613,742    451,496  
 

 

 

  

 

 

  

 

 

 

Other income and (expenses):

   

Loss on extinguishment of debt

  (94,612  —      —    

Interest expense, net of amounts capitalized

  (259,725  (193,510  (92,701

Losses on interest rate swaps

  —      (67,908  (26,353

Other, net

  (7,792  (7,167  (2,661
 

 

 

  

 

 

  

 

 

 
  (362,129  (268,585  (121,715
 

 

 

  

 

 

  

 

 

 

Income (loss) from continuing operations before income taxes

  443,905    (110,047  (300,062

Income tax benefit (expense)

  (5,466  (4,241  4,221  
 

 

 

  

 

 

  

 

 

 

Income (loss) from continuing operations

  438,439    (114,288  (295,841

Discontinued operations:

   

Losses on sale of assets, net of taxes

  —      —      (158

Loss from discontinued operations, net of taxes

  —      —      (2,193
 

 

 

  

 

 

  

 

 

 
  —      —      (2,351

Net income (loss)

 $438,439   $(114,288 $(298,192
 

 

 

  

 

 

  

 

 

 

Income (loss) per unit—continuing operations:

   

Basic

 $2.52   $(0.80 $(2.48
 

 

 

  

 

 

  

 

 

 

Diluted

 $2.51   $(0.80 $(2.48
 

 

 

  

 

 

  

 

 

 

Loss per unit—discontinued operations:

   

Basic

 $—     $—     $(0.02
 

 

 

  

 

 

  

 

 

 

Diluted

 $—     $—     $(0.02
 

 

 

  

 

 

  

 

 

 

Net income (loss) per unit:

   

Basic

 $2.52   $(0.80 $(2.50
 

 

 

  

 

 

  

 

 

 

Diluted

 $2.51   $(0.80 $(2.50
 

 

 

  

 

 

  

 

 

 

Weighted average units outstanding:

   

Basic

  172,004    142,535    119,307  
 

 

 

  

 

 

  

 

 

 

Diluted

  172,729    142,535    119,307  
 

 

 

  

 

 

  

 

 

 

Distributions declared per unit

 $2.70   $2.55   $2.52  
 

 

 

  

 

 

  

 

 

 
   Year Ended December 31, 
   2018  2017  2016 
   (in thousands, except per share data) 

Revenues

    

Oil sales

  $275,239  $76,876  $30,565 

Natural gas sales

   46,966   46,303   16,093 

Natural gas sales – Affiliates

   29,090   2,908   —   

Natural gas liquid sales

   51,467   35,217   8,307 

Natural gas liquid sales – Affiliates

   37,005   5,081   —   

Gain (loss) on derivative contracts

   78,054   (6,797  —   
  

 

 

  

 

 

  

 

 

 

Total revenues

   517,821   159,588   54,965 

Operating Expenses

    

Production expenses

   47,600   16,872   5,090 

Gathering, transportation and processing

   —     18,602   5,920 

Production taxes

   17,579   3,685   1,087 

Exploration expenses

   43,303   32,629   5,258 

Depreciation, depletion, amortization and accretion

   123,922   37,376   24,996 

General and administrative

   60,874   31,357   5,581 

Gain on sale of oil and natural gas properties

   —     (838  —   
  

 

 

  

 

 

  

 

 

 

Total operating expenses

   293,278   139,683   47,932 

Total operating income

   224,543   19,905   7,033 

Other income (expense)

    

Interest expense, net

   (8,352  (1,461  (86

Other income

   —     13   —   
  

 

 

  

 

 

  

 

 

 

Net income before income taxes

   216,191   18,457   6,947 

Income tax expense

   356,862   —     —   
  

 

 

  

 

 

  

 

 

 

Net (loss) income

  $(140,671 $18,457  $6,947 
  

 

 

  

 

 

  

 

 

 

Earnings (loss) per share

    

Basic

  $(0.92 $0.18  $0.11 
  

 

 

  

 

 

  

 

 

 

Diluted

  $(0.92 $0.18  $0.11 
  

 

 

  

 

 

  

 

 

 

Weighted average number of shares outstanding

    

Basic

   152,232   100,473   62,394 
  

 

 

  

 

 

  

 

 

 

Diluted

   152,232   100,473   62,394 
  

 

 

  

 

 

  

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

Index to Financial Statements
F-7


Roan Resources, Inc.

LINN ENERGY, LLCConsolidated Statements of Changes in Equity

CONSOLIDATED STATEMENTS OF UNITHOLDERS’ CAPITAL

 

   Units  Unitholders’
Capital
  Accumulated
Income
(Deficit)
  Treasury
Units
(at Cost)
  Total
Unitholders’

Capital
 
   (in thousands) 

December 31, 2008

   114,080   $2,109,089   $651,597   $—     $2,760,686  

Sale of units, net of underwriting discounts and expenses of $12,369

   14,950    279,299    —      —      279,299  

Issuance of units

   1,098    494    —      —      494  

Cancellation of units

   (187  (2,696  —      2,696    —    

Purchase of units

    —      —      (2,696  (2,696

Distributions to unitholders

    (303,316  —      —      (303,316

Unit-based compensation expenses

    15,089    —      —      15,089  

Reclassification of distributions paid on forfeited restricted units

    63    —      —      63  

Excess tax benefit from unit-based compensation

    577    —      —      577  

Net loss

    —      (298,192  —      (298,192
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

December 31, 2009

   129,941    2,098,599    353,405    —      2,452,004  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Sale of units, net of underwriting discounts and expenses of $34,556

   28,750    809,774    —      —      809,774  

Issuance of units

   815    4,418    —      —      4,418  

Cancellation of units

   (496  (11,832  —      11,832    —    

Purchase of units

    —      —      (11,832  (11,832

Distributions to unitholders

    (365,711  —      —      (365,711

Unit-based compensation expenses

    13,792    —      —      13,792  

Reclassification of distributions paid on forfeited restricted units

    59    —      —      59  

Net loss

    —      (114,288  —      (114,288
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

December 31, 2010

   159,010    2,549,099    239,117    —      2,788,216  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Sale of units, net of underwriting discounts and expenses of $27,427

   17,514    651,522    —      —      651,522  

Issuance of units

   1,371    7,446    —      —      7,446  

Cancellation of units

   (530  (17,352  —      17,352    —    

Purchase of units

    —      —      (17,352  (17,352

Distributions to unitholders

    (466,488  —      —      (466,488

Unit-based compensation expenses

    22,243    —      —      22,243  

Reclassification of distributions paid on forfeited restricted units

    79    —      —      79  

Excess tax benefit from unit-based compensation

    4,805    —      —      4,805  

Net income

    —      438,439    —      438,439  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

December 31, 2011

   177,365   $2,751,354   $677,556   $—     $3,428,910  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
  Stockholders’ Equity       
  Common
Stock
(Shares)
  Common
Stock
  Additional
Paid-in
Capital
  Accumulated
Deficit
  Members’
Equity
  Total Equity 
  (in thousands) 

Balance at December 31, 2015

  —    $—    $—    $—    $98,292  $98,292 

Contributions from Citizen Members

  —     —     —     —     169,008   169,008 

Net income

  —     —     —     —     6,947   6,947 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance at December 31, 2016

  —     —     —     —     274,247   274,247 

Contributions from Citizen Members

  —     —     —     —     95,557   95,557 

Distributions to Citizen Members

  —     —     —     —     (85,614  (85,614

Acquisition of oil and natural gas properties in exchange for equity units

  —     —     —     —     1,281,743   1,281,743 

Equity-based compensation

  —     —     —     —     379   379 

Net income

  —     —     —     —     18,457   18,457 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance at December 31, 2017

  —     —     —     —     1,584,769   1,584,769 

Acquisition of oil and natural gas properties in exchange for equity units

  —     —     —     —     39,906   39,906 

Equity-based compensation (1)

  —     —     3,162   —     7,868   11,030 

Net (loss) income (1)

  —     —     —     (151,520  10,849   (140,671

Issuance of common stock upon Reorganization

  152,540   153   1,643,239   —     (1,643,392  —   
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance at December 31, 2018

  152,540  $153  $1,646,401  $(151,520 $—    $1,495,034 
 

 

 

 ��

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

(1)

Amounts are allocated to stockholders’ equity and members’ equity to reflect the Reorganization. SeeNote 10 – Equityfor discussion of the Reorganization.

The accompanying notes are an integral part of these consolidated financial statements.

Index to Financial Statements
F-8


Roan Resources, Inc.

LINN ENERGY, LLCConsolidated Statements of Cash Flows

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

   Year Ended December 31, 
   2011  2010  2009 
   (in thousands) 

Cash flow from operating activities:

    

Net income (loss)

  $438,439   $(114,288 $(298,192

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

    

Depreciation, depletion and amortization

   334,084    238,532    201,782  

Impairment of long-lived assets

   —      38,600    —    

Unit-based compensation expenses

   22,243    13,792    15,089  

Loss on extinguishment of debt

   94,612    —      —    

Amortization and write-off of deferred financing fees and other

   23,828    27,014    21,824  

(Gains) losses on sale of assets and other, net

   (281  1,718    (22,842

Deferred income tax

   310    3,088    (6,436

Mark-to-market on derivatives:

    

Total (gains) losses

   (449,940  (7,303  167,727  

Cash settlements

   237,134    302,875    362,936  

Cash settlements on canceled derivatives

   26,752    (123,865  48,977  

Premiums paid for derivatives

   (134,352  (120,376  (93,606

Changes in assets and liabilities:

    

(Increase) decrease in accounts receivable—trade, net

   (120,055  (66,283  29,117  

(Increase) decrease in other assets

   (2,951  2,926    (3,051

Increase (decrease) in accounts payable and accrued expenses

   58,216    25,457    (4,675

Increase (decrease) in other liabilities

   (9,333  49,031    8,154  
  

 

 

  

 

 

  

 

 

 

Net cash provided by operating activities

   518,706    270,918    426,804  
  

 

 

  

 

 

  

 

 

 

Cash flow from investing activities:

    

Acquisition of oil and natural gas properties, net of cash acquired

   (1,500,193  (1,351,033  (130,735

Development of oil and natural gas properties

   (574,635  (204,832  (170,458

Purchases of other property and equipment

   (55,229  (18,181  (7,784

Proceeds from sale of properties and equipment and other

   (303  (7,362  26,704  
  

 

 

  

 

 

  

 

 

 

Net cash used in investing activities

   (2,130,360  (1,581,408  (282,273
  

 

 

  

 

 

  

 

 

 

Cash flow from financing activities:

    

Proceeds from sale of units

   678,949    844,330    291,668  

Proceeds from borrowings

   2,534,240    3,300,816    639,203  

Repayments of debt

   (1,301,029  (2,150,000  (704,893

Distributions to unitholders

   (466,488  (365,711  (303,316

Financing fees, offering expenses and other, net

   (56,358  (93,343  (71,511

Excess tax benefit from unit-based compensation

   4,805    —      577  

Purchase of units

   (17,352  (11,832  (2,696
  

 

 

  

 

 

  

 

 

 

Net cash provided by (used in) financing activities

   1,376,767    1,524,260    (150,968
  

 

 

  

 

 

  

 

 

 

Net increase (decrease) in cash and cash equivalents

   (234,887  213,770    (6,437

Cash and cash equivalents:

    

Beginning

   236,001    22,231    28,668  
  

 

 

  

 

 

  

 

 

 

Ending

  $1,114   $236,001   $22,231  
  

 

 

  

 

 

  

 

 

 
   Year Ended December 31, 
   2018  2017  2016 
   (in thousands) 

Cash flows from operating activities

    

Net (loss) income

  $(140,671 $18,457  $6,947 

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

    

Depreciation, depletion, amortization and accretion

   123,922   37,376   24,996 

Unproved leasehold amortization and impairment

   36,046   25,377   5,258 

Gain on sale of oil and natural gas properties

   —     (838  —   

Amortization of deferred financing costs

   853   175   —   

Amortization of deferred rent

   902   —     —   

(Gain) loss on derivative contracts

   (78,054  6,797   —   

Net cash (paid) received upon settlement of derivative contracts

   (33,279  2,705   —   

Equity-based compensation

   11,030   379   —   

Deferred income taxes

   356,862   —     —   

Other

   2,971   (11  (41

Changes in operating assets and liabilities increasing (decreasing) cash:

    

Accounts receivable – Oil, natural gas and natural gas liquid sales

   18,963   (62,170  (12,473

Accounts receivable – Affiliates

   (4,974  (4,695  —   

Accounts receivable – Joint interest owners and other

   (136,367  (8,729  (35,398

Prepaid drilling advances

   (28,977  —     —   

Prepaid expenses

   (1,992  (2,312  (1,221

Other current assets

   (2,584  (2  3 

Accounts payable

   16,733   —     6,006 

Accrued liabilities

   21,536   47,801   8,403 

Accounts payable and accrued liabilities – Affiliates

   (23,645  31,121   —   

Drilling advances

   31,058   (25,363  22,760 

Revenue payable

   97,963   (5,793  10,900 
  

 

 

  

 

 

  

 

 

 

Net cash provided by operating activities

   268,296   60,275   36,140 

Cash flows from investing activities

    

Acquisition of oil and natural gas properties

   (22,935  (42,701  (144,774

Capital expenditures for oil and natural gas properties

   (673,465  (167,122  (96,335

Acquisition of other property and equipment

   (3,237  (1,332  —   

Proceeds from sale of oil and natural gas properties

   10,545   1,435   —   

Other

   —     (2,801  —   
  

 

 

  

 

 

  

 

 

 

Net cash used in investing activities

   (689,092  (212,521  (241,109

Cash flows from financing activities

    

Proceeds from borrowings

   429,300   105,339   20,000 

Repayment of borrowings

   —     (40,000  —   

Deferred financing costs

   (2,279  (2,885  —   

Deferred offering costs

   (813  —     —   

Contributions from Citizen members

   —     95,557   169,008 

Distributions to Citizen members

   —     (11,147  —   
  

 

 

  

 

 

  

 

 

 

Net cash provided by financing activities

   426,208   146,864   189,008 
  

 

 

  

 

 

  

 

 

 

Net increase (decrease) in cash and cash equivalents

   5,412   (5,382  (15,961

Cash and cash equivalents, beginning of year

   1,471   6,853   22,814 
  

 

 

  

 

 

  

 

 

 

Cash and cash equivalents, end of year

  $6,883  $1,471  $6,853 
  

 

 

  

 

 

  

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

F-9


Roan Resources, Inc.

Consolidated Statements of Cash Flows, Continued

   Year Ended December 31, 
   2018   2017  2016 
   (in thousands) 

Supplemental disclosure of cash flow information

     

Cash paid for interest, net of capitalized interest

  $7,029   $1,036  $86 
  

 

 

   

 

 

  

 

 

 

Supplemental disclosure ofnon-cash investing and financing activities

     

Change in accrued capital expenditures

  $65,699   $147,142  $4,922 

Acquisition of oil and natural gas properties for equity

  $39,906   $1,281,743  $—   

Distribution to Citizen Members of assets and liabilities

  $—     $(74,467 $—   

The accompanying notes are an integral part of these consolidated financial statements.

F-10


Roan Resources, Inc.

IndexNotes to Consolidated Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNote 1 – Business and Organization

Roan Resources, Inc. (“Roan Inc.”) was formed in September 2018 to facilitate a reorganization and to become the holding company for Roan Resources LLC (“Roan LLC”). In September 2018, a series of transactions were executed with Roan LLC’s members which resulted in Roan LLC becoming a wholly- owned subsidiary of Roan Inc. These transactions are hereafter referred to as the “Reorganization” and Roan Inc. with its subsidiaries are collectively referred to as the “Company.” SeeNote 1—10 – Equityfor further discussion of the Reorganization transaction. The accompanying historical financial statements through the date of Reorganization are the financial statements of Roan LLC, our accounting predecessor. Following the Reorganization, the historical financial statements are the results of Roan Inc.

Roan LLC was initially formed by Citizen Energy II, LLC (“Citizen”) in May 2017. On August 31, 2017, the Companyexecuted a contribution agreement (the “Contribution Agreement”) by and among Roan LLC, Citizen, Linn Energy Holdings, LLC (“LEH”) and Linn Operating, LLC (“LOI”, and together with LEH, “Linn”) pursuant to which, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within anarea-of-mutual-interest to the Company (collectively the “Contribution”). In exchange for their contributions, Citizen and Linn each received a 50% equity interest in Roan LLC.

The contributions of oil and natural gas properties to Roan LLC by Citizen and Linn were determined to meet the definition of a business. However, as Roan LLC had no assets or operations prior to the Contribution, it was determined that Citizen was the acquirer for accounting purposes in accordance with ASC Topic 805,Business Combinations. As a result, the information in the accompanying financial statements and footnotes for the period prior to the Contribution reflects the historical results of Citizen. Citizen was formed in July 2014 to engage in the acquisition, exploration, development, production, and sale of oil and natural gas reserves in Central Oklahoma. Subsequent to the Contribution, the information in the accompanying financial statements and footnotes reflects the results of Roan LLC and after the Reorganization, the results of Roan Inc. SeeNote 4 – Acquisitions for additional discussion of the business combination of the oil and natural gas properties contributed by Linn. In conjunction with the Contribution Agreement, the Company entered into management services agreements with both Citizen and Linn (“MSAs”) through April 2018. SeeNote 12 – Transactions with Affiliates for additional discussion of the MSAs and transactions with Citizen and Linn.

The Company was formed to engage in the acquisition, exploration, development, production, and sale of oil and natural gas reserves. The Company’s oil and natural gas properties are located in Central Oklahoma. The Company’s corporate headquarters is located in Oklahoma City, Oklahoma.

Note 2 – Basis of Presentation and Significant Accounting Policies

NatureBasis of BusinessPresentation

Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company that began operationsThe accompanying consolidated financial statements were prepared in March 2003 and was formed as a Delaware limited liability company in April 2005. The Company completed its initial public offering (“IPO”) in January 2006 and its units representing limited liability company interests (“units”) are listed on The NASDAQ Global Select Market under the symbol “LINE.” LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are locatedconformity with accounting principles generally accepted in the United States (“U.S.”), primarily in the Mid-Continent, the Permian Basin, Michigan, California and the Williston Basin.

The operations of the Company are governed by the provisions of a limited liability company agreement executed by and among its members. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of the Company’s unitholders. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (the “Delaware Act”) and the Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (the “Agreement”), unitholders have no liability for the debts, obligations and liabilities of the Company, except as expressly required in the Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the Agreement.

Principles of Consolidation and Reporting

The Company presents its financial statements in accordance with U.S. generally accepted accounting principlesAmerica (“GAAP”). The consolidated financial statements of the Company include the accounts of the CompanyRoan Inc. and its wholly ownedwholly-owned subsidiaries. All significant intercompany transactionsbalances and balancestransactions have been eliminated upon consolidation. Investmentseliminated.

Certain amounts in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. Subsequent events were evaluated through the issuance date of the financial statements.

The consolidatedprior period financial statements for previous periods include certain reclassifications that were madehave been reclassified to conform to currentthe 2018 presentation. SuchThese reclassifications havehad no impact on previously reported net income (loss), total stockholders’ equity or unitholders’ capital.total cash flows.

Discontinued Operations

Discontinued operations in 2009 primarily represent activity related to post-closing adjustments associated with the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations disposed of in 2008.

Use of Estimates

The preparation of the accompanying consolidated financial statements and related footnotes in conformity with GAAP requires that management of the Company to makeformulate estimates and assumptions about future events. These estimatesthat affect revenues, expenses, assets, liabilities and the underlying assumptions affect the amount

Roan Resources, Inc.

Notes to Consolidated Financial Statements

disclosure of assets and liabilities reported, disclosures about contingent assets and liabilities,liabilities. A significant item that requires management’s estimates and reported amountsassumptions is the estimate of revenuesproved oil, natural gas and expenses. The estimates thatNGL reserves which are particularly significant toused in the financial statements include estimatescalculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Revenue Recognition

Revenues from the sale of oil, natural gas and NGLs are recognized when control of the product has been transferred to the customer, all performance obligations have been satisfied and collectability is reasonably assured. We recognize revenues from the sale of oil, natural gas liquids (“NGL”), future cash flowsand NGLs based on our share of volumes sold. SeeNote 3 – Revenue from oilContracts with Customers for additional discussion.

Fair Value Measurements

The Company follows a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and natural gas properties, depreciation, depletionminimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.

Level 3 – Unobservable inputs that are not corroborated by market data and amortization, asset retirement obligations,may be used with internally developed methodologies that result in management’s best estimate of fair value.

The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during 2018 or 2017.

Business Combinations

The Company accounts for all business combinations using the acquisition method, which involves the use of significant judgment. In a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of commoditythe acquisition date. Any excess or shortage of amounts assigned to assets and interest rate derivatives, if any, andliabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill.

The Company estimates the fair values of assets acquired and liabilities assumed. As fair value isassumed in a market-based measurement, it is determined based on thebusiness combination using various assumptions that market participants would use. These estimates and assumptions(all of which are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The ASU will be applied retrospectively and is effective for periods beginning on or after January 1, 2013. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

In May 2011, the FASB issued an ASU that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changesLevel 3 inputs within the fair value measurement requirements for certain financial instruments,hierarchy). The most significant assumptions typically relate to the estimated fair values assigned to proved and sets forth additional disclosure requirements for otherunproved oil and natural gas properties. To estimate the fair value measurements. The ASU will be applied prospectively and is effective for periods beginning after December 15, 2011. The Company is currently evaluating the impact, if any,values of the adoption of this ASU on its consolidated financial statementsproved and related disclosures.

Cash Equivalents

For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.

Accounts Receivable—Trade, Net

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at December 31, 2011, and December 31, 2010.

Inventories

Materials, supplies and commodity inventories are valued at the lower of average cost or market.

Oil and Natural Gas Properties

Proved Properties

The Company accounts forunproved oil and natural gas properties, in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.Company

Index

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

 

develops estimates of oil, natural gas and NGL reserves. Estimates of reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Additionally, a risk factor is applied to reserves by reserve type based on industry standards. The Company evaluatesestimates future prices to apply to the impairmentestimated net quantities of its proved oilreserves based on the applicable ownership percentage acquired and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii)costs to arrive at estimates of future commodity prices; and (iv)net cash flows. The future net cash flows are discounted using a market-based weighted average cost of capital rate. rate determined appropriate at the time of the acquisition.

Oil and Natural Gas Properties

The underlying commodity prices embedded inCompany follows the Company’ssuccessful efforts method to account for its exploration and production activities. Under this method, costs incurred to purchase, lease, or otherwise acquire a property, whether unproved or proved, are capitalized when incurred. The Company initially capitalizes exploratory well costs pending a determination whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells.

Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed as incurred. Additionally, costs to operate and maintain wells and field equipment are expensed as incurred.

Depletion is computed using theunits-of-production method on a field level basis over the remaining estimated cash flowslife of proved reserves. The Company determined its oil and natural gas properties are comprised of one single field. Capitalized drilling and development costs of producing oil and natural gas properties are amortized based on the producttotal estimated proved developed reserves. Proved leasehold costs associated with proved reserves are depleted based on total proved reserves, which includes proved undeveloped reserves. Under theunit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. The Company recorded depletion expense on capitalized oil and natural gas properties of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted$122.2 million, $37.0 million, and $24.9 million for estimated locationthe years ended December 31, 2018, 2017, and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs2016, respectively.

Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property.

The net carrying values of retired, sold or abandoned proved properties that constitute less than a partcomplete unit of an amortization basedepletable property are charged, or credited, net of proceeds, to accumulatedaccumulate depreciation, depletion and amortization unless doing so significantly affectsaffect theunit-of-production amortization rate, in which case a gain or loss is recognized currently.to earnings. Gains or losses from the disposal of other propertiescomplete units of depletable property are recognized currently. Expendituresin earnings.

Proceeds from sales of all or a partial interest in individual unproved properties assessed for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortizedimpairment on a unit-of-productiongroup basis overare accounted for as a recovery of costs. No gain or loss is recognized unless the remaining lifesales proceeds exceed the original cost of the related proved developed reserves. entire interest in the property, in which a gain will be recognized for the excess.

The Company capitalizes interest on borrowed funds relatedexpenditures made in connection with exploration and development projects that are not subject to its share of costs associated with the drilling and completion of new oil and natural gas wells.current amortization. Interest is capitalized only duringfor the periodsperiod that activities are in whichprogress to bring these assets are broughtprojects to their intended use. The Company capitalized interest costs of approximately $2$8.3 million $1 million and $300,000 for the year ended December 31, 2018. No interest was capitalized in the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.2017 or 2016.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

Impairment of Oil and Natural Gas Properties

Proved Propertiesoil and natural gas properties are evaluated for impairment when facts or circumstances indicate that the carrying value of those assets may not be recoverable, such as when there are declines in oil and natural gas prices or well performance. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. An impairment loss is indicated if the sum of the estimated undiscounted future cash flows related to an asset group is less than the carrying value of that asset group. If an impairment loss has been incurred, the loss recognized is the excess of the carrying amount over the estimated fair value.

BasedThe Company calculates the estimated fair value using a discounted future cash flow model. Management’s assumptions associated with the calculation of future cash flows include oil and natural gas prices based on NYMEX futures price strips, as well as other assumptions, including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes, (v) timing of development, and (vi) estimated reserves. A discount rate, consistent with that used by market participants, is applied to the analysis described above,estimated future cash flows in order to estimate fair value. Cash flow estimates for impairment testing exclude the Company recorded noeffects of derivative instruments.

It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) oil and natural gas futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, and (iv) results of future drilling activities. No impairment charge of proved oil and natural gas properties was recorded for the years ended December 31, 2011,2018, 2017, and December 31, 2009. For the year ended December 31, 2010, the Company recorded a noncash impairment charge, before and after tax, of approximately $39 million primarily associated with proved oil and natural gas properties related to an unfavorable marketing contract. 2016.

The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.

Unproved Properties

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values ofCompany’s unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved propertiesassessed for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an assetannually, or more frequently if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million, $5 million and $7 million for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, which are included in “exploration costs” on the consolidated statements of operations.

Other Property and Equipment

Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual assetevents or group of assets.

Revenue Recognition

Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.

The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2011, and December 31, 2010, the Company had natural gas production imbalance receivables of approximately $19 million and $18 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $9 million and $8 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.

The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.

The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in Brea, California. Any excess electricity is sold to the California wholesale power market. This revenue is included in “other revenues” on the consolidated statements of operations.

Restricted Cash

Restricted cash of approximately $4 million and $3 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2011, and December 31, 2010, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Derivative Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts and put options. In addition, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2011, the Company had no outstanding interest rate swap agreements.

Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate these contracts as cash flow hedges; therefore, the changes in faircircumstances dictated that the carrying value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.

Unit-Based Compensation

The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based payments granted to employees and nonemployee directors. The fair value of unit-based payments, excluding liability awards, is computed at the date of grant and isassets may not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company currently does not have any awards accounted for as liability awards.

The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation.

The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is reported in “excess tax benefit from unit-based compensation” on the consolidated statements of unitholders’ capital.

Deferred Financing Fees

The Company incurred legal and bank fees related to the issuance of debt (see Note 6). At December 31, 2011, and December 31, 2010, net deferred financing fees of approximately $94 million and $102 million, respectively, are included in “other noncurrent assets” on the consolidated balance sheets. These debt issuance costs are amortized over the life of the debt agreement.recoverable. For the years ended December 31, 2011, December 31, 2010,2017 and December 31, 2009, amortization2016, the Company recorded abandonment and impairment expense on its unproved oil and natural gas properties of approximately $16 million, $17$4.5 million and $14$5.3 million, respectively, for leases which have expired, or are expected to expire. Impairment expense on unproved oil and natural gas properties is included in “interestexploration expense in the accompanying consolidated statements of operations. No impairment of unproved oil and natural gas properties was recorded for the year ended December 31, 2018.

Unproved leasehold costs are amortized on a group basis if individually insignificant, and a valuation allowance is established with a monthly amortization charge to exploration expense for the portion of the properties’ total cost that management estimates may never be transferred to proved properties during the terms of the respective leases. The impairment amortization rate considers the Company’s current drilling plans, the remaining terms of the respective leases and the results of exploratory drilling activity, and can be affected by economic factors including oil and natural gas price outlooks, projected capital costs, and available liquidity. For the years ended December 31, 2018 and 2017, the Company recorded amortization expense on its unproved oil and natural gas properties of $36.0 million and $19.6 million, respectively, which is reflected in exploration expense on the accompanying consolidated statements of operations. There was no such expense recorded for the year ended December 31, 2016. Costs of expired or relinquished leases are charged against the valuation allowance.

Derivative Instruments

The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production.

The commodity derivative instruments are measured at fair value and are included in the balance sheet as derivative assets and derivative liabilities, on a net basis by counterparty. The Company adjusts the valuations

Roan Resources, Inc.

Notes to Consolidated Financial Statements

from the valuation model for nonperformance risk and for counterparty risk. The fair values of amounts capitalized”the Company’s commodity derivative instruments are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The Company has not designated any of the derivative contracts as fair value or cash flow hedges for accounting purposes for any of the periods presented. Accordingly, net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments and are included in gain (loss) on derivative contracts in the consolidated statements of operations. The Company’s cash flow is impacted when the settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty and are reflected as operating activities in the Company’s consolidated statements of cash flows. The Company’s firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not requiremark-to-market accounting treatment.

Index to Financial Statements

LINN ENERGY, LLCAccrued Liabilities

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

The components of accrued liabilities are presented below:

 

   December 31, 
   2018   2017 
   (in thousands) 

Accrued capital expenditures

  $151,965   $7,252 

Accrued production expenses

   10,879    —   

Accrued general and administrative expenses

   7,450    2,696 

Other

   6,200    297 
  

 

 

   

 

 

 

Total accrued liabilities

  $176,494   $10,245 
  

 

 

   

 

 

 

Fair Value of Financial InstrumentsDrilling Advances

The carrying valuesCompany’s drilling advances consist of the Company’s receivables, payables and Credit Facility (as defined in Note 6) are estimated to be substantially the same as their fair values at December 31, 2011, and December 31, 2010. See Note 6 for fair value disclosures relatedcash provided to the Company’s other outstanding debt.Company from its joint interest partners for planned drilling activities. Advances are applied against the joint interest partner’s share of expenses incurred. As noted above, the Company carriesentered into MSAs with Citizen and Linn to perform services, including operating the contributed assets. At December 31, 2017 and through the termination of the MSAs, Citizen and Linn maintained any drilling advances from joint interest partners. SeeNote 12 – Transactions with Affiliatesfor discussion of the MSAs with Citizen and Linn.

Asset Retirement Obligation

The Company is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company’s asset retirement obligations (“ARO”) relate to the plugging of wells and the related abandonment of oil and natural gas properties. AROs are recognized as liabilities with an increase to the carrying amounts of the related assets when the obligation is incurred. The cost of the asset, including ARO, is depreciated over the useful life of the asset. Fair value of ARO is measured using the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value and the liability is settled or the well is sold, at which time the liability is removed. Accretion expense is included in accretion expense in the consolidated statements of operations.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains its derivativecash balances at credit-worthy financial instrumentsinstitutions that are insured by the Federal Deposit Insurance Corporation (“FDIC”). At times, cash balances may be in excess of FDIC limits. The Company has not incurred any losses related to the amounts in excess of FDIC limits.

Accounts Receivable

Accounts receivable consists mainly of receivables from oil, natural gas and NGL purchasers and joint interest owners on properties the Company operates. Accounts receivable from the sale of oil, natural gas and NGLs are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. The Company routinely reviews outstanding balances, assesses the financial strength of its purchasers and joint interest owners and records a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts, existing economic conditions and other pertinent factors. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At December 31, 2018, the Company recorded an allowance for doubtful accounts of $3.3 million related to receivables from joint interest owners. The Company had no reserve for bad debts at fair value. See Note 8 for details aboutDecember 31, 2017.

Deferred Financing Costs

Costs incurred in connection with the Company’s debt are capitalized and amortized as interest expense over the scheduled maturity period. Unamortized costs are associated with the Company’s revolving credit facility and are reflected as a component of long-term assets in the consolidated balance sheets.

Equity-Based Compensation

Equity-based compensation is measured based on the grant date fair value of the award and recognized over the requisite service period. For employees directly involved in exploration and development activities, equity compensation is capitalized to the Company’s derivative financial instruments.oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses or production expense in the consolidated statements of operations. The Company accounts for forfeitures of stock compensation as they occur. As of December 31, 2018, no forfeitures have occurred.

Earnings (Loss) per Share

The Company uses the treasury stock method to determine the potential dilutive effect of outstanding performance share units and restricted stock units. Refer toNote 11 – Equity Compensationfor details on the Company’s performance share units and restricted stock units.

Income Taxes

The Company is a limited liability companycorporation and therefore a taxable entity. Our predecessor, Roan LLC, was treated as a partnershipflow-through entity for federalincome tax purposes. As a result, the net taxable income or loss of Roan LLC and stateany related tax credits, for income tax purposes, withflowed through to its members. Accordingly, no tax provision was made in the exceptionhistorical financial statements of Roan LLC since the income tax was an obligation of its members. As a result of the states of Texas and Michigan, with income tax liabilities and/or benefits ofReorganization, the Company passed throughrecorded a deferred tax liability based on the change in its tax status.

Roan Resources, Inc.

Notes to unitholders. As such, with the exception of the states of Texas and Michigan, theConsolidated Financial Statements

The Company is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below.

Limited liability companies are subject to state income taxes in Texas and Michigan. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. Deferredrecognizes deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards.bases. Deferred income tax assets and liabilities are measured using enacted tax rates expectedapplicable to apply to taxable income in the years in whichfuture period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. SeeNote 14 13 – Income Taxesfor detail of amounts recordedfurther information on the Company’s taxes.

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements.

Note 2—Acquisitions, Divestitures and Discontinued Operations

Acquisitions—2011

On December 15, 2011, To recognize a tax position, the Company completeddetermines whether it is more likely than not, based on technical merits, that the acquisitiontax position will be sustained upon examination. Any interest or penalties would be recognized as a component of certainincome tax expense.

Defined Contribution Plan

In 2018, the Company adopted a 401(k) retirement plan and health and welfare benefit plans in which our employees are eligible to participate. Under the 401(k) retirement plan, the Company provides for an employer match of employee contributions of up to 6% of eligible compensation and a profit-sharing contribution of up to 8% of eligible compensation. For the year ended December 31, 2018, the Company paid $1.2 million in contributions to the plan.

Comprehensive Income

The Company has no elements of comprehensive income other than net income.

Concentrations of Credit Risk

The Company sells oil, natural gas and NGLs to various types of customers. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. Additionally, limitations on capacity at processing plants could also impact the Company’s ability to sell its oil, natural gas and NGLs. The Company is subject to credit risk resulting from the concentration of its oil, natural gas and NGL receivables with its significant purchasers. The Company does not believe the loss of any single purchaser would materially impact its results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.

For the years ended December 31, 2018, 2017, and 2016, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues:

   Years Ended
December 31,
 
   2018  2017  2016 

Coffeyville Resources Refining & Marketing LLC

   31  *   * 

Sunoco Inc.

   18  40  55

Blue Mountain Midstream LLC

   15  *   * 

EnLink Oklahoma Gas Processing, LP

   13  39  31

*

Revenue from customer was less than 10% in this period.

Blue Mountain Midstream LLC (“Blue Mountain”) is deemed a related party as it is a wholly-owned subsidiary of Riviera Resources, Inc. (“Riviera”). SeeNote 12 – Transactions with Affiliates.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

The Company’s derivative transactions have been carried out in theover-the-counter market. The entry into derivative transactions in theover-the-counter market involves the risk that the counterparties, which are financial institutions, may be unable to meet the financial terms of the transactions. The Company monitors on an ongoing basis the credit ratings of its derivative counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. The counterparties to the Company’s derivative contracts at December 31, 2018 are also lenders under its revolving credit facility. As a result, the Company does not require collateral or other security from counterparties nor is the Company required to post collateral to support derivative instruments. The Company has master netting agreements with all of its derivative counterparties, which allow the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.

Commitments and Contingencies

The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated.

Risks and Uncertainties

Historically, the markets for oil, natural gas, and NGLs have experienced significant price fluctuations. Price fluctuations can result from variations in weather, regional levels of production, availability of transportation capacity, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities.

A portion of the Company’s oil and natural gas properties located primarilyproduction may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, transportation or refining facilities or equipment or field labor issues, or intentionally as a result of market conditions such as oil or natural gas prices that the Company deems uneconomic. If a substantial amount of the Company’s production is interrupted or shut in, the Granite Wash of TexasCompany’s cash flows and, Oklahoma from Plains Exploration & Production Company (“Plains”). Thein turn, it’s financial condition and results of operations could be materially and adversely affected.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU2014-09,Revenue from Contracts with Customers (Topic 606)(“ASC 606”). This guidance supersedes most of these properties havethe existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. Subsequent to the issuance of ASU2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU2016-08,Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)(“ASU2016-08”), pertaining to the presentation of revenues on a gross basis (revenues presented separately

Roan Resources, Inc.

Notes to Consolidated Financial Statements

from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Applying the guidance in ASU2016-08 requires significant judgment in determining the point in time when control of products transfers to customers. Effective January 1, 2018, the Company adopted ASC 606 using the modified retrospective method of transition under which the standard is applied only to the most current period presented. Accordingly, comparative information has not been includedadjusted and continues to be reported under the previous revenue standard. SeeNote 3 – Revenue from Contracts with Customers for discussion of the impact upon adoption and the additional disclosures.

Recently Issued Accounting Standards Not Yet Adopted

In February 2016, the FASB issued ASU2016-02,Leases (Topic 842)(“ASU2016-02”). This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the consolidatedstatement of financial statements sinceposition a liability to make lease payments (the lease liability) and aright-of-use asset representing its right to use the acquisitionunderlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for fiscal years beginning after December 15, 2018, including interim reporting periods within those fiscal years, with early application permitted. The Company enters into lease agreements to support its operations, such as office space, drilling rigs and field equipment. ASU2016-02 will not impact the accounting or financial presentation of the Company’s mineral leases.

The Company plans to adopt the new standard using the simplified transition method described in ASU2018-11Leases (Topic 842): Targeted Improvements, and therefore will apply the new standard as of January 1, 2019. Accordingly, comparative information will not be adjusted and will continue to be reported under the previous lease standard. The Company plans to elect the package of practical expedients within ASU2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. The Company paid approximately $544also plans to elect the practical expedient under ASU2018-01Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842that allows it to not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASU2016-02 on its financial statements, accounting policies, and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures. At this time, the impact upon adoption of ASU2016-02 and other related ASUs is expected to result in recognition of additional operating liabilities ranging from $7 million in total considerationto $12 million, with correspondingright-of-use assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for these properties. existing operating leases.

The transaction was financed initiallynew standard also provides practical expedients for an entity’s ongoing accounting. The Company currently plans to elect the short-term lease recognition exemption for all leases that qualify and the practical expedient to not separate lease andnon-lease components for the majority of classes of underlying assets.

Note 3 – Revenue from Contracts with borrowings underCustomers

The Company adopted ASC 606 on January 1, 2018 using a modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The adoption does not have a

Roan Resources, Inc.

Notes to Consolidated Financial Statements

material impact on the timing of the Company’s Credit Facility,revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company’s presentation of revenues and expenses under thegross-versus-net presentation guidance in ASU2016-08.

The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as defined in Note 6.compared to the previous revenue recognition standard, ASC Topic 605,Revenue Recognition (“ASC 605”):

On November 1, 2011,

   Year Ended December 31, 2018 
   Under ASC
606
   Under ASC
605
   Increase/
(decrease)
 
   (in thousands) 

Revenues

      

Oil sales

  $275,239   $275,399   $(160

Natural gas sales

  $76,056   $96,086   $(20,030

Natural gas liquid sales

  $88,472   $114,021   $(25,549

Operating expenses

      

Gathering, transportation and processing

  $—     $45,739   $(45,739

Net loss

  $(140,671  $(140,671  $—   

Oil Sales

Most of the Company’s oil contracts transfer physical custody and November 18, 2011,title at or near the wellhead, which is commonly when control of the oil has been transferred to the purchaser. The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price. Any differentials incurred after the transfer of control of the oil are net against oil sales as they represent part of the transaction price of the contract. For its oil contracts, the Company completed two acquisitionsgenerally records its sales based on the net amount received.

Natural Gas and NGL Sales

Most of the Company’s natural gas is sold at the wellhead or inlet to the processor’s facility, which is commonly when control of the natural gas has been transferred to the purchaser. The natural gas is sold under percentage of proceeds processing contracts. Under these contracts, the purchaser gathers the natural gas where it is produced and transports it via pipeline to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue gas are then sold by the purchaser. Under the natural gas percentage of proceeds contracts, the Company receives a percentage of the value for the extracted NGLs and the residue gas.

For its natural gas processing contracts, the Company generally records its natural gas and NGL sales net of gathering, processing and transportation expenses based on a principal versus agent assessment for individual contracts.

Performance Obligations

The Company satisfies the performance obligations under its oil and natural gas sales contracts through delivery of its production and transfer of control to a customer. Upon delivery of production, the Company has the right to receive consideration from its customers in amounts that correspond with the value of the production transferred. The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery for operated properties and within 90 days of the month of delivery fornon-operated properties.

The Company’s oil sales contracts are short-term in nature with a contract term of one year or less. For those contracts, the Company utilized the practical expedient in ASC 606, which provides an exemption from

Roan Resources, Inc.

Notes to Consolidated Financial Statements

disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s natural gas and NGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

The Company recognizes sales of oil, natural gas, and NGLs at a point in time when it satisfies a performance obligation and at that point the Company has an unconditional right to receive payment. Accordingly, these contracts do not give rise to contract assets or contract liabilities under ASC 606. The Company had accounts receivable related to revenue from contracts with customers of approximately $65.2 million as of December 31, 2018, which represent this unconditional right to receive payment.

Prior Period Performance Obligations

To record revenues for oil, natural gas and NGLs, the Company estimates the amount of production delivered at the end of each month and the prices expected to be received for those sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer. For the year ended December 31, 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Note 4 – Acquisitions

Linn Acquisition

As noted inNote 1 – Business and Organization, in connection with the Contribution, Roan LLC acquired from Linn certain oil and natural gas properties located in the Permian Basin. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company paid approximately $108 million in cash and recorded a payable of approximately $2 million, resulting in total considerationCentral Oklahoma (the “Linn Acquisition”). In exchange for the acquisitions of approximately $110 million. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On June 1, 2011, the Company completed the acquisition of certaincontributed oil and natural gas properties, Linn received a 50% equity interest in Roan LLC valued at approximately $1.3 billion based on the Cleveland play, located invalue of the Texas Panhandle, from Panther Energybusiness. Accordingly, the fair value of the Company LLC and Red Willow Mid-Continent, LLC (collectively referred to as “Panther”). The resultswas primarily comprised of operationsthe fair value of these properties have been included incontributed oil and natural gas properties. SeeNote 10 – Equityfor further discussion of the consolidated financial statements sinceequity issued to Linn.

Because the acquisition date. The Company paid approximately $223 million in total consideration for these properties. The transactionLinn Acquisition was financed primarily with proceeds fromdetermined to be a business combination as the Company’s May 2011 debt offering, as described below.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

On May 2, 2011, and May 11, 2011, the Company completed two acquisitions of certainacquired oil and natural gas properties located inmet the Williston Basin.definition of a business, the acquired assets and liabilities were recorded at fair value as of August 31, 2017, the acquisition date. The following assumptions were used to determine the fair value of the oil and natural gas properties:

Discount rate

9.50%

Reserve risk factor (1)

35%-100%

Oil price

three years NYMEX WTI forward curve

Natural gas price

three years NYMEX Henry Hub forward curve

NGL price

39% of oil price

Price escalation (2)

2.00%

Roan Resources, Inc.

Notes to Consolidated Financial Statements

(1)

Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%.

(2)

Prices were escalated at the end of the forward curve

The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands):

Consideration given

  

Equity units

  $1,281,743 
  

 

 

 

Allocation of purchase price

  

Inventory

  $205 

Proved oil and natural gas properties

   214,647 

Unproved oil and natural gas properties

   1,086,600 
  

 

 

 

Total assets acquired

   1,301,452 

Asset retirement obligations

   (7,547

Revenue suspense

   (12,162
  

 

 

 

Total fair value of net assets acquired

  $1,281,743 
  

 

 

 

The following unaudited pro forma combined results of operations is provided for the years ended December 31, 2017 and 2016 as though the Linn Acquisition had been completed as of these propertiesthe earliest period presented at the time of the acquisition. The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of the assets acquired in the Linn Acquisition.

These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition.

   (Unaudited) 
   Years Ended
December 31,
 
   2017   2016 
   (in thousands) 

Revenue

  $215,161   $90,238 

Net income

  $44,873   $26,378 

Acquisitions of Unproved Properties

During the year ended December 31, 2017, the Company acquired, from unrelated third parties, interests in approximately 23,400 net acres of leasehold in separately negotiated transactions for aggregate cash consideration of $49.7 million, all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties.

As discussed inNote 12 – Transactions with Affiliates, Citizen and Linn acquired acreage during 2017 on behalf of Roan LLC for $63.0 million, which was included in the consolidated financial statements since the acquisition dates. The Companyaccounts payable and accrued liabilities – affiliates at December 31, 2017. In March 2018, Roan LLC paid approximately $154Linn $22.9 million in cash and recorded a receivable of approximately $1 million, resulting in total consideration forissued equity units to both Citizen and Linn to settle the acquisitions of approximately $153 million. amount due.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

Note 5 – Oil and Natural Gas Properties

The transactions were financed initially with borrowings under the Company’s Credit Facility.

On April 1, 2011, and April 5, 2011, the Company completed two acquisitions of certain oil and natural gas properties locatedare in the Permian Basin, including properties from SandRidge Exploration and Production, LLC (“SandRidge”).continental United States. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company paid approximately $239 million in total consideration for the acquisitions. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties located in the Williston Basin from an affiliate of Concho Resources Inc. (“Concho”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition date. The Company paid $196 million in cash and recorded a receivable from Concho of approximately $2 million, resulting in total consideration for the acquisition of approximately $194 million. The transaction was financed primarily with proceeds from the Company’s March 2011 public offering of units, as described below.

During 2011, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company, in the aggregate, paid approximately $38 million in total consideration for these properties.

These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):

Assets:

  

Current

  $5,981  

Noncurrent

   748  

Oil and natural gas properties

   1,516,737  
  

 

 

 

Total assets acquired

  $1,523,466  
  

 

 

 

Liabilities:

  

Current

  $2,130  

Asset retirement obligations

   19,853  
  

 

 

 

Total liabilities assumed

  $21,983  
  

 

 

 

Net assets acquired

  $1,501,483  
  

 

 

 

Current assets include receivables, prepaids and inventory and noncurrent assets include other property and equipment. Current liabilities include payables, ad valorem taxes payable and other liabilities.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include the following:

   December 31, 
   2018   2017 
   (in thousands) 

Oil and natural gas properties

    

Proved

  $1,538,379   $750,492 

Unproved

   1,089,954    1,126,459 

Less: accumulated depreciation, depletion, amortization and impairment

   (230,836   (78,307
  

 

 

   

 

 

 

Oil and natural gas properties, net

  $2,397,497   $1,798,644 
  

 

 

   

 

 

 

There were no exploratory well costs pending determination of proved reserves at December 31, 2018 or 2017 nor any unsuccessful exploratory dry hole costs during the years ended December 31, 2018 and 2016. During the year ended December 31, 2017, there was $1.3 million ofpre-drilling costs associated with an exploratory dry hole that is included in exploration costs in the accompanying consolidated statements of operations.

Note 6 – Asset Retirement Obligations

The following is a reconciliation of the changes in the Company’s ARO for the years ended December 31, 2018 and 2017:

   Years Ended December 31, 
           2018                   2017         
   (in thousands) 

Asset retirement obligation, beginning balance

  $10,769   $2,245 

Liabilities incurred or acquired (1)

   3,347    8,118 

Revisions in estimated cash flows (2)

   2,018    42 

Liabilities settled

   (139   —   

Accretion expense

   853    364 
  

 

 

   

 

 

 

Asset retirement obligation, ending balance

   16,848    10,769 

Less: current portion of obligations

   790    —   
  

 

 

   

 

 

 

Asset retirement obligation – long term

  $16,058   $10,769 
  

 

 

   

 

 

 

(1)

For the year ended December 31, 2017, liabilities incurred or acquired included $7.5 million assumed as part of the Linn Acquisition.

(2)

For the year ended December 31, 2018, revisions primarily represent changes in the economic lives of producing properties and the Company’s share of estimated costs.

Note 7 – Long-Term Debt

In September 2017, the Company entered into a $750.0 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (as amended, the “2017 Credit Facility”). In September 2018, the redetermination resulted in an increase to the borrowing base to $675.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of

Roan Resources, Inc.

Notes to Consolidated Financial Statements

December 31, 2018, the Company had $514.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility. At December 31, 2018, the weighted average interest rate on borrowings under our 2017 Credit Facility was 5.21%. The 2017 Credit Facility is secured by substantially all of the assets of the Company.

The Company amended the 2017 Credit Facility in September 2018 to increase the borrowing base as noted above as well as to allow for permitted additional debt of up to $500 million before any reduction in the borrowing base would occur, to reduce the applicable margin for both London Interbank Offered Rate (“LIBOR”) and alternate base rate (“ABR”) loans by 0.25% for each utilization level, and to reduce the commitment fee rate for the two lowest utilization levels to 0.375%.

Principal maturities of the Company’s borrowings at December 31, 2018, consisting of amounts outstanding under the 2017 Credit Facility, are as follows (in thousands):

2019

  $—   

2020

   —   

2021

   —   

2022

   514,639 
  

 

 

 
  $514,639 
  

 

 

 

Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR at the Company’s election. The rate used for ABR loans is based on the higher of the prime rate, the federal funds effective rate plus 0.50% or theone-month LIBOR rate plus 1%. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides for a commitment fee, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement):

Utilization Level

  

Utilization

  

LIBOR Margin

  

ABR Margin

  

Commitment Fee

Level I

  <25%  2.00%  1.00%  0.375%

Level II

  >25% but <50%  2.25%  1.25%  0.375%

Level III

  >50% but <75%  2.50%  1.50%  0.500%

Level IV

  >75% but <90%  2.75%  1.75%  0.500%

Level V

  >90%  3.00%  2.00%  0.500%

The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report.

The 2017 Credit Facility also contains financial covenants requiring the Company to comply with a leverage ratio of the Company’s consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the

Roan Resources, Inc.

Notes to Consolidated Financial Statements

period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of the Company’s consolidated current assets to consolidated current liabilities (as defined in the credit agreement to excludenon-cash assets and liabilities under ASC Topic 815Derivatives and Hedging and ASC Topic 410Asset Retirement and Environmental Obligations) as of the fiscal quarter ended of not less than 1.00 to 1.00.

As of December 31, 2018, the Company was in compliance with the covenants under the 2017 Credit Facility.

Prior to the 2017 Credit Facility, Citizen had atwo-year, $500.0 million credit facility (“Citizen 2017 Credit Facility”) with an initial borrowing base of $82.5 million. In August 2017, the Citizen 2017 Credit Facility was terminated and the outstanding balance of $20.3 million was repaid.

Note 8 – Derivative Instruments

The Company utilizes fixed price swaps and basis swaps to manage the price risk associated with the sale of its oil, natural gas and NGL production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential, the Panhandle Eastern Pipeline or Natural Gas Pipeline Company of AmericaMid-Continent. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume.

The following table reflects the Company’s open commodity contracts at December 31, 2018:

   2019   2020   Total 

Oil fixed price swaps

      

Volume (Bbl)

   5,405,670    1,599,500    7,005,170 

Weighted-average price

  $60.05   $63.14   $60.76 

Natural gas fixed price swaps

      

Volume (MMBtu)

   43,800,000    12,325,000    56,125,000 

Weighted-average price

  $2.90   $2.63   $2.84 

Natural gas basis swaps

      

Volume (MMBtu)

   29,200,000    3,640,000    32,840,000 

Weighted-average price

  $0.60   $0.62   $0.60 

Natural gas liquids fixed price swaps

      

Volume (Bbl)

   1,095,000    —      1,095,000 

Weighted-average price

  $32.25   $—     $32.25 

The Company nets the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the right to offset exists. SeeNote 9 – Fair Value Measurementsfor further information regarding the fair value measurement of the Company’s derivatives.

As the Company has elected to not account for commodity derivative instruments as hedging instruments, gains or losses resulting from the change in fair value along with the gains or losses resulting in settlement of derivative contracts are reflected in gain (loss) on derivative contracts included in the consolidated statement of operations.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

The following table presents the Company’s gain (loss) on derivative contracts and net cash (paid) received upon settlement of its derivative contracts for the years ended December 31, 2018 and 2017:

   Years Ended December 31, 
           2018                   2017         
   (in thousands) 

Gain (loss) on derivative contracts

  $78,054   $(6,797

Net cash (paid) received upon settlement of derivative contracts (1)

  $(33,279  $2,705 

(1)

Includes $1.3 million of cash received upon settlement of derivative contracts prior to their contractual maturity for the year ended December 31, 2017.

There were no gains or losses on derivative contracts in the year ended December 31, 2016 and no derivative contracts outstanding as of December 31, 2016.

Note 9 – Fair Value Measurements

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company’s recurring fair value measurements are performed for its commodity derivatives.

Commodity Derivative Instruments

Commodity derivative contracts are stated at fair value in the accompanying consolidated balance sheets. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of December 31, 2018 and 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):

   December 31, 2018 
   Level 1   Level 2  Level 3   Gross Fair
Value
  Netting  Carrying
Value
 

Assets

         

Current commodity derivatives

  $—     $85,728  $—     $85,728  $(3,548 $82,180 

Noncurrent commodity derivatives

   —      21,565   —      21,565   (927  20,638 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total assets

  $—     $107,293  $—     $107,293  $(4,475 $102,818 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Liabilities

         

Current commodity derivatives

  $—     $(4,393 $—     $(4,393 $3,548  $(845

Noncurrent commodity derivatives

   —      (1,068  —      (1,068  927   (141
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total liabilities

  $—     $(5,461 $—     $(5,461 $4,475  $(986
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 
   December 31, 2017 
   Level 1   Level 2  Level 3   Gross Fair
Value
  Netting  Carrying
Value
 

Assets

         

Current commodity derivatives

  $—     $2,856  $—     $2,856  $(2,704 $152 

Noncurrent commodity derivatives

   —      2,182   —      2,182   (1,186  996 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total assets

  $—     $5,038  $—     $5,038  $(3,890 $1,148 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Liabilities

         

Current commodity derivatives

  $—     $(11,983 $—     $(11,983 $2,704  $(9,279

Noncurrent commodity derivatives

   —      (2,557  —      (2,557  1,186   (1,371
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total liabilities

  $—     $(14,540 $—     $(14,540 $3,890  $(10,650
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Non-Recurring Fair Value Measurements

The Company utilizes fair value on anon-recurring basis to review its proved oil and natural gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on management’s estimated net discounted futurecash-flows of proved property. Unobservable inputs included estimates of: (i) reserves; (ii) futureof oil and natural gas production, as the case may be, from the Company’s reserve reports, commodity prices based on the sales contract terms or forward price curves, operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows;costs, and (v)a discount rate based on a market-based weighted average cost of capital rate.(all of which are Level 3 inputs within the fair value hierarchy).

The revenuesCompany’snon-recurring fair value measurements include the purchase price allocations for the fair value of assets and expenses related toliabilities acquired through business combinations and the properties acquired from Plains, Panther, SandRidge and Concho are included in the condensed consolidated results of operationsdetermination of the Company as of December 15, 2011, June 1, 2011, April 1, 2011, and March 31, 2011, respectively. The following unaudited pro forma financial information presents a summarygrant date fair value of the Company’s condensed consolidated resultsperformance share units. The fair value of assets and liabilities acquired through business combinations is calculated using adiscounted-cash flow approach using level 3 inputs. The fair value of assets or liabilities associated with purchase price allocations is on anon-recurring basis and is not measured in periods after initial recognition. The grant date fair value of the Company’s performance share units is determined using a Monte Carlo simulation model and is classified as a Level 3 measurement. Please refer toNote 4 – Acquisitions andNote 11 – Equity Compensationfor additional discussion.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

Other Financial Instruments

The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying values of cash and cash equivalents, accounts payable, revenue payable, and accounts receivable approximate fair values due to the short-term maturities of these instruments and the carrying value of long-term debt approximates fair value as the applicable interest rates are variable and reflective of market rates.

Note 10 – Equity

In September 2018 and in conjunction with the Reorganization, the Company issued 152.5 million shares of its Class A common stock to the members of Roan LLC in exchange for their equity interest in Roan LLC. The Reorganization was accounted for as a reverse recapitalization with Roan Inc. as the accounting acquirer and therefore did not result in any change in the accounting basis for the underlying assets. Net income before taxes and equity-based compensation were allocated ratably to the members of Roan LLC and the stockholders of Roan Inc. for the period before and after the Reorganization, respectively. For comparative purposes, the issuance of the shares to the members of Roan LLC at the time of the Reorganization was reflected on a retroactive basis with the units outstanding during each period presented.

For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company Agreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued 1.5 billion membership units representing capital interests in Roan LLC (the “LLC Units”) for a 50% equity interest in Roan LLC, to Linn in exchange for the contribution of oil and natural gas properties. SeeNote 4 – Acquisitions for additional discussion of the Linn Acquisition. Additionally, Roan LLC issued 1.5 billion LLC Units, which represented a 50% equity interest in Roan LLC, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the LLC Units issued to Citizen was the same as that of the LLC Units issued to Linn.

As discussed inNote 4 – Acquisitions, Citizen and Linn acquired acreage during 2017 on Roan LLC’s behalf. In March 2018, Roan LLC issued 19.2 million LLC Units to each Citizen and Linn for the additional leasehold acreage.

For the period January 1, 2017 through August 31, 2017, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (the “Citizen Operating Agreement”), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B interests. Class A interests represented capital interests in Citizen and Class B interests represented interests in profits, losses and distributions. Distributions were made to the Class A interests and Class B interests members pro rata in accordance with their membership interests; however, once the Class A interests members received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B interests members received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement.

Note 11 – Equity Compensation

The Company has adopted the Roan Resources, Inc. Amended and Restated Management Incentive Plan (the “Plan”), which provides for grants of options, stock appreciation rights, restricted stock unit, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

Performance Share Units

Prior to the Reorganization, Roan LLC granted performance share units to certain of its employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of performance share units under the Plan, hereafter referred to as the “PSUs,” and are subject to the terms of the Plan and individual award agreements. The amount of PSUs that can be earned range from 0% to 200% based on the Company’s market value on December 31, 2020 (“Performance Period End Date”). The Company’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the Company’s Class A common stock for the 30 consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the issuance of one share of the Company’s Class A common stock. Other than the security in which the PSUs are settled, no terms of the PSUs were modified in connection with the conversion of the PSUs.

The following table presents activity for the Company’s PSUs during the years ended December 31, 2018 and 2017.

   Number of
PSUs
   Weighted
Average Fair
Value
   Total
Fair Value
($ in thousands)
 

Outstanding at December 31, 2016

   —     $—     $—   

Granted

   16,350,000    1.41    23,054 

Vested

   —      —      —   
  

 

 

   

 

 

   

 

 

 

Outstanding at December 31, 2017

   16,350,000   $1.41   $23,054 

Granted

   6,825,000    1.88    12,810 

Vested

   —      —      —   

Conversion (1)

   (22,016,250   —      —   
  

 

 

   

 

 

   

 

 

 

Outstanding at December 31, 2018

   1,158,750   $30.95   $35,864 
  

 

 

   

 

 

   

 

 

 

(1)

PSUs were converted on a basis of 0.05 to 1.0. There was no change to the deemed fair value of the awards based on assessment of modification.

Compensation expense associated with the PSUs for the years ended December 31, 2011,2018 and December 31, 2010, assuming the acquisitions of Plains, Panther, SandRidge2017 was $11.0 million and Concho had been completed as of January 1, 2010, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of this date.

   Year Ended
December 31,
 
   2011   2010 
   

(in thousands, except

per unit amounts)

 

Total revenues and other

  $1,819,878    $939,572  

Total operating expenses

  $901,967    $720,360  

Net income (loss)

  $528,046    $(86,952

Net income (loss) per unit:

    

Basic

  $3.01    $(0.57
  

 

 

   

 

 

 

Diluted

  $3.00    $(0.57
  

 

 

   

 

 

 

Other

In July 2010, the Company entered into a definitive purchase$0.4 million, respectively, and sale agreement (“PSA”) to acquire certain oil and natural gas properties for a contract price of $95 million. Upon the execution of the PSA, the Company paid a deposit of approximately $9 million. In September 2010, in accordance with the terms of the PSA, the Company terminated the PSA as a result of certain conditions to closing not being met. The other party to the PSA disputed the termination of the PSA and held the deposit. On March 28, 2011, an arbitration panel granted a favorable final ruling to the Company with regard to the termination of the PSA and the return of the deposit. The deposit plus interest was received by the Company in April 2011.

Acquisitions—2010 and 2009

The following is a summary of certain significant acquisitions completed by the Company during the years ended December 31, 2010, and December 31, 2009:

On November 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin from Element Petroleum, LP for approximately $118 million.

On October 14, 2010, the Company completed two acquisitions of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin from Crownrock, LP and Patriot Resources Partners LLC for approximately $260 million.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

On August 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin from Crownrock, LP and Element Petroleum, LP for approximately $95 million.

On May 27, 2010, the Company completed the acquisition of interests in Henry Savings LP and Henry Savings Management LLC that primarily hold oil and natural gas properties located in the Permian Basin for approximately $323 million.

On April 30, 2010, the Company completed the acquisition of interests in two wholly owned subsidiaries of HighMount Exploration & Production LLC that hold oil and natural gas properties in the Antrim Shale located in northern Michigan for approximately $327 million.

On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico from certain affiliates of Merit Energy Company for approximately $151 million.

On August 31, 2009, and September 30, 2009, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian Corporation for approximately $114 million.

Divestitures

In 2009, certain post-closing matters related to the 2008 sale of the deep rights interests in certain central Oklahoma acreage were resolved and the Company recorded a gain of approximately $25 million, which is included in “(gains) lossesgeneral and administrative expenses on sale of assets and other, net” on the accompanying consolidated statements of operations for the year ended December 31, 2009.

Discontinued Operations

Discontinued operations of approximately $2 million in 2009 primarily represent activity related to post-closing adjustments associated with the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations disposed of in 2008.

Note 3—Unitholders’ Capital

Equity Distribution Agreement

On August 23, 2011, the Company entered into an equity distribution agreement, pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. In connection with entering into the agreement, the Company incurred expenses of approximately $423,000. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

In September 2011, the Company issued and sold 16,060 units representing limited liability company interests at an average unit price of $38.25 for proceeds of approximately $602,000 (net of approximately $12,000 in commissions). In December 2011, the Company issued and sold 772,104 units representing limited liability company interests at an average unit price of $38.03 for proceeds of approximately $29 million (net of approximately $587,000 in commissions). In connection with the issue and sale of these units, the Company incurred professional service expenses of approximately $139,000. The Company used the net proceeds for

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At December 31, 2011, units equaling approximately $470 million in aggregate offering price remained available to be issued and sold under the agreement.

Public Offering of Units

In March 2011, the Company sold 16,726,067 units representing limited liability company interests at $38.80 per unit ($37.248 per unit, net of underwriting discount) for net proceeds of approximately $623 million (after underwriting discount and offering expenses of approximately $26 million). The Company used a portion of the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Senior Notes and 2018 Senior Notes and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Senior Notes and 2018 Senior Notes (see Note 6). The Company used the remaining net proceeds from the sale of units to finance a portion of the March 31, 2011, acquisition in the Williston Basin.

In December 2010, the Company sold 11,500,000 units representing limited liability company interests at $35.92 per unit ($34.48 per unit, net of underwriting discount) for net proceeds of approximately $396 million (after underwriting discount and offering expenses of approximately $17 million). The Company used the net proceeds from the sale of these units to repay all outstanding indebtedness under its Credit Facility and for other general corporate purposes, including the partial notes redemption (see Note 6).

In March 2010, the Company sold 17,250,000 units representing limited liability company interests at $25.00 per unit ($24.00 per unit, net of underwriting discount) for net proceeds of approximately $414 million (after underwriting discount and offering expenses of approximately $17 million). The Company used a portion of the net proceeds from the sale of these units to finance the HighMount acquisition.

In October 2009, the Company sold 8,625,000 units representing limited liability company interests at $21.90 per unit ($21.024 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering expenses of approximately $8 million). The Company used the net proceeds from the sale of these units to reduce indebtedness under the Credit Facility.

In May 2009, the Company sold 6,325,000 units representing limited liability company interests at $16.25 per unit ($15.60 per unit, net of underwriting discount) for net proceeds of approximately $98 million (after underwriting discount and offering expenses of approximately $4 million). The Company used the net proceeds from the sale of these units to reduce indebtedness under the Credit Facility.

Equity Distribution Agreement and Public Offering of Units—Subsequent Events

In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $1 million in commissions). The Company used the net proceeds for general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At January 31, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.

In January 2012, the Company also completed a public offering of units in which it sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $28 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Unit Repurchase Plan

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. During the year ended December 31, 2011, 529,734 units were repurchased at an average unit price of $32.76 for a total cost of approximately $17 million. During the year ended December 31, 2010, 486,700 units were repurchased at an average unit price of $23.79 for a total cost of approximately $12 million. During the year ended December 31, 2009, 123,800 units were repurchased at an average unit price of $12.99 for a total cost of approximately $2 million. All units were subsequently canceled.

At December 31, 2011, approximately $56 millionoperations. There was available for unit repurchase under the program. The timing and amounts of anyno such repurchases will be at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are repurchased at fair market value on the date of repurchase.

Issuance and Cancellation of Units

During the years ended December 31, 2010, and December 31, 2009, the Company purchased 9,055 units and 63,031 units for approximately $300,000 and $1 million, respectively, in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan (see Note 5). All units were subsequently canceled. The Company purchased no unitsexpense during the year ended December 31, 2011.

Distributions

Under the Agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Distributions paid by the Company are presented on the consolidated statements of unitholders’ capital. On January 27, 2012, the Company’s Board of Directors declared a cash distribution of $0.69 per unit with respect to the fourth quarter of 2011. The distribution, totaling approximately $138 million, was paid February 14, 2012, to unitholders of record as of the close of business February 7, 2012.

Note 4—Business and Credit Concentrations

Cash

The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash.

Revenue and Trade Receivables

The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1).

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

For the year ended December 31, 2011, the Company’s three largest customers represented 13%, 10% and 10%, respectively, of the Company’s sales. For the year ended December 31, 2010, the Company’s three largest customers represented 17%, 14% and 13%, respectively, of the Company’s sales. For the year ended December 31, 2009, the Company’s three largest customers represented 22%, 18% and 15%, respectively, of the Company’s sales.

At December 31, 2011, trade accounts receivable from three customers represented approximately 12%, 10% and 10%, respectively, of the Company’s receivables. At December 31, 2010, trade accounts receivable from three customers represented approximately 16%, 12% and 11%, respectively, of the Company’s receivables.

Note 5—Unit-Based Compensation and Other Benefit Plans

Incentive Plan Summary

The Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (the “Plan”), originally became effective in December 2005. The Plan, which is administered by the Compensation Committee of the Board of Directors (“Compensation Committee”), permits granting unit grants, unit options, restricted units, phantom units and unit appreciation rights to employees, consultants and nonemployee directors under the terms of the Plan. The unit options and restricted units vest ratably over three years. The contractual life of unit options is 10 years. Unit awards were initially issued in conjunction with the Company’s IPO in January 2006.

The Plan limits the number of units that may be delivered pursuant to awards to 12.2 million units. The Board of Directors and the Compensation Committee have the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits to the participant without the consent of the participant.

Upon exercise or vesting of an award of units, or an award settled in units, the Company will issue new units, acquire units on the open market or directly from any person, or use any combination of the foregoing, at the Compensation Committee’s discretion. If the Company issues new units upon exercise or vesting of an award, the total number of units outstanding will increase. To date, the Company has issued awards of unit grants, unit options, restricted units and phantom units. The Plan provides for all of the following types of awards:

Unit Grants—A unit grant is a unit that vests immediately upon issuance.

Unit Options—A unit option is a right to purchase a unit at a specified price at terms determined by the Compensation Committee. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant, and in general, will become exercisable over a vesting period but may accelerate upon a change in control of the Company. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s unvested unit options will be automatically forfeited unless the option agreement or the Compensation Committee provides otherwise.

Restricted Units—A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture, and may contain such terms as the Compensation Committee shall determine. The Company intends the restricted units under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of its units. Therefore, Plan participants will not pay any consideration for the restricted units they receive. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s unvested restricted units will be automatically forfeited unless the Compensation Committee or the terms of the award agreement provide otherwise.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Phantom Units/Unit Appreciation Rights—These awards may be settled in units, cash or a combination thereof. Such grants contain terms as determined by the Compensation Committee, including the period or terms over which phantom units vest. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s phantom units or unit appreciation rights will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. While phantom units require no payment from the grantee, unit appreciation rights will have an exercise price that will not be less than the fair market value of the units on the date of grant. At December 31, 2011, the Company had 36,784 phantom units issued and outstanding. To date, the Company has not issued unit appreciation rights.

Securities Authorized for Issuance Under the Plan

As of December 31, 2011, approximately 1.4 million units were issuable under the Plan pursuant to outstanding award or other agreements, and 5.2 million additional units were reserved for future issuance under the Plan.

Accounting for Unit-Based Compensation

The Company recognizes as2016. Unrecognized expense beginning at the grant date, the fair value of unit options and other equity-based compensation issued to employees and nonemployee directors. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Company’s consolidated statements of operations. A summary of unit-based compensation expenses included on the consolidated statements of operations is presented below:

   Year Ended December 31, 
   2011   2010   2009 
   (in thousands) 

General and administrative expenses

  $21,131    $13,450    $14,743  

Lease operating expenses

   1,112     342     346  
  

 

 

   

 

 

   

 

 

 

Total unit-based compensation expenses

  $22,243    $13,792    $15,089  
  

 

 

   

 

 

   

 

 

 

Income tax benefit

  $8,219    $5,096    $5,968  
  

 

 

   

 

 

   

 

 

 

Restricted/Unrestricted Units

The fair value of unrestricted unit grants and restricted units issued is determined based on the fair market value of the Company units on the date of grant. A summary of the status of the nonvested units as of December 31, 2011, is presented below:

   Number of
Nonvested
Units
  Weighted
Average
Grant-Date
Fair Value
 

Nonvested units at December 31, 2010

   1,451,556   $21.16  

Granted

   1,110,502   $38.54  

Vested

   (651,760 $20.22  

Forfeited

   (50,636 $33.32  
  

 

 

  

Nonvested units at December 31, 2011

   1,859,662   $31.54  
  

 

 

  

The weighted average grant-date fair value of unrestricted unit grants and restricted units granted2018 for all outstanding PSU awards was $25.89 and $16.11 during the years ended December 31, 2010, and December 31, 2009, respectively.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

As of December 31, 2011, there was approximately $38$24.4 million, of unrecognized compensation cost related to nonvested restricted units. The cost is expected towhich will be recognized over a weighted-average remaining period of 2.0 years. Under the treasury stock method, the PSUs are antidilutive for the weighted average periodshare calculation and therefore are excluded from dilutive weighted average shares in the accompanying consolidated statements of approximately 1.5 years. operations.

The totalgrant date fair value of the PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units that vested was approximately $13 million, $14 millionearned and $11 million forestimated Company value on the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

In January 2012,Performance Period End Date. The grant date fair value of the Company granted 913,663 restricted units as part of its annual review of its employees, including executives, compensation.

Changes in Unit Options and Unit Options OutstandingPSUs is expensed on a straight-line basis from the grant date to the Performance Period End Date.

The following provides information related to unit option activitytable shows the range of assumptions that were used for the year ended December 31, 2011:

   Number of
Units
Underlying
Options
  Weighted
Average
Exercise Price
Per Unit
   Weighted
Average
Grant-Date

Fair Value
   Weighted
Average
Remaining
Contractual
Life in Years
 

Outstanding at December 31, 2010

   1,720,393   $22.48    $3.05     6.71  

Exercised

   (310,400 $23.99    $3.83    
  

 

 

      

Outstanding at December 31, 2011

   1,409,993   $22.14    $2.87     5.83  
  

 

 

      

Exercisable at December 31, 2011

   1,282,526   $22.76    $3.11     5.70  
  

 

 

      

No unit options were granted duringMonte Carlo simulation model to determine the years ended December 31, 2011, or December 31, 2010. The weighted average grant-dategrant date fair value of optionsand associated compensation expense for the PSUs granted was $0.55 during the year ended December 31, 2009. The total intrinsic value of options exercised was approximately $5 million, $2 million and $124,000, during the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively. The Company received approximately $7 million from the exercise of options during the year ended December 31, 2011.

As of December 31, 2011, total unrecognized compensation cost related to nonvested unit options was approximately $4,000. The cost is expected to be recognized over a weighted average period of approximately one month. In addition, the exercisable unit options at December 31, 2011, have an aggregate intrinsic value of approximately $19 million and all outstanding unit options have an aggregate intrinsic value of approximately $22 million. The total fair value of all options that vested during the years ended December 31, 2011, December 31, 2010, and December 31, 2009, was approximately $500,000, $1 million and $2 million, respectively. No options expired during the years ended December 31, 2011, December 31, 2010, or December 31, 2009.

The fair value of unit-based compensation for unit options was estimated on the date of grant using a Black-Scholes pricing model based on certain assumptions. The Company’s determination of the fair value of unit-based payment awards is affected by the Company’s unit price as well as assumptions regarding a number of complex and subjective variables. The Company’s employee unit options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and often are expected to be exercised prior to their contractual maturity.

Expected volatilities used in the estimation of fair value have been determined using available volatility data for the Company as well as an average of volatility computations of other identified peer companies in the oil and natural gas industry. Expected distributions are estimated based on the Company’s distribution rate at the date of grant. Historical data of the Company and other identified peer companies is used to estimate expected term because, due to the limited period of time its equity units have been publicly traded, the Company does not

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

have sufficient historical exercise data to compute a reasonable estimate. Forfeitures are estimated using historical Company data and are revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. All employees granted awards have been determined to have similar behaviors for purposes of determining the expected term used to estimate fair value. The risk-free rate for periods within the expected term of the unit option is based on the U.S. Treasury yield curve in effect at the time of grant. The fair values of the 2009 unit option grants were based upon the following assumptions:2018:

 

Company enterprise value (in billions)

  2009$4.19 – $4.56 

ExpectedEquity volatility

   30.59%34.0% – 36.0% 

Expected distributions

15.80% – 16.79%

Risk-freeWeighted average risk-free interest rate

   1.24%1.96% – 1.91%

Expected term

5 years2.54% 

Although

Roan Resources, Inc.

Notes to Consolidated Financial Statements

Restricted Stock Units

Under the Plan, the Company is authorized to issue restricted stock and restricted stock units to eligible employees. The Company estimates the fair valuevalues of unit option grantsrestricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is determinedexpensed over the applicable vesting period.

The following table presents activity for the Company’s restricted stock units during the year ended December 31, 2018:

   Number of
Restricted
Stock Units
   Weighted
Average
Fair Value
   Total
Fair Value
($ in thousands)
 

Outstanding at December 31, 2017

   —     $—     $—   

Granted

   11,800    16.95    200 

Vested

   —      —      —   

Forfeited

   —      —      —   
  

 

 

   

 

 

   

 

 

 

Outstanding at December 31, 2018

   11,800   $16.95   $200 
  

 

 

   

 

 

   

 

 

 

Compensation expense associated with the restricted stock units for the year ended December 31, 2018 was $0.03 million and is included in general and administrative expenses on the accompanying consolidated statements of operations. There were no restricted stock units issued prior to 2018. As of December 31, 2018, the Company’s unrecognized compensation cost related to unvested restricted stock units was $0.2 million, which will be recognized over a weighted-average remaining period of 0.9 year. Under the treasury stock method, the restricted stock units are antidilutive for the weighted average share calculation and therefore are excluded from dilutive weighted average shares in the accompanying consolidated statements of operations.

Note 12 – Transactions with Affiliates

Management Service Agreements

Under the MSAs, Citizen and Linn provided certain services in respect to the oil and natural gas properties they contributed to the Company. Such services included serving as operator of the oil and natural gas properties contributed, land administration, marketing, information technology and accounting services. As a result of Citizen and Linn continuing to serve as operator of the contributed assets and contracting directly with vendors for goods and services for operations, Citizen and Linn collected amounts due from joint interest owners for their share of costs and billed the Company for its share of costs. The services provided under the MSAs ended in April 2018 when the Company took over as operator for the oil and natural gas properties contributed by Citizen and Linn. In conjunction with the conclusion of the MSAs in April 2018, the Company assumed certain working capital accounts associated with the properties contributed from Citizen and Linn.

For each of the years ended December 31, 2018 and 2017, the Company incurred approximately $10.0 million for charges related to the services provided under the MSAs, which are recorded in general and administrative expenses in the accompanying consolidated statements of operations.

Through April 2018, Citizen and Linn billed the Company for its share of operating costs in accordance with applicable accounting standards, using a Black-Scholes pricing model, that value may not be indicativethe MSAs. At December 31, 2017, the Company had $55.5 million and $46.5 million due to Linn and Citizen, respectively, included in accounts payable and accrued liabilities – affiliates in the accompanying consolidated balance sheets. At December 31, 2017, the Company had $19.0 million due to Linn and Citizen for revenue suspense associated with the oil and natural gas properties contributed to the Company included in accounts payable and accrued liabilities – affiliates in the accompanying consolidated balance sheets.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

Acquisition of Acreage

As provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage within an area of mutual interest on behalf of the fair value observedCompany. As of December 31, 2017, the additional acreage acquired totaled $63.0 million and the Company reflected the amount due to Citizen and Linn in accounts payable and accrued liabilities – affiliates. SeeNote 4 – Acquisitions andNote 10 – Equityfor further discussion of the settlement of the payable due to Citizen and Linn related to the additional acquired acreage.

Natural Gas Dedication Agreement

The Company has a willing buyer/willing seller market transaction.gas dedication agreement with Blue Mountain, a subsidiary of Riviera, which has directors and shareholders in common with the Company. Amounts due from Blue Mountain at December 31, 2018 and 2017 are reflected as accounts receivable – affiliates in the accompanying consolidated balance sheets and represent accrued revenue for the Company’s portion of the production sold to Blue Mountain. Sales to Blue Mountain are reflected as natural gas sales – affiliates and NGL sales – affiliates in the accompanying consolidated statements of operations. See further discussion of this gas dedication agreement inNote 14 – Commitments and Contingencies.

Nonemployee GrantsCorporate Office Lease

During 2018, the Company entered into a lease for office space in Oklahoma City, Oklahoma that is owned by a subsidiary of Riviera under a lease with an initial term of 5 years with an option to extend the lease for an additional 5 years at the end of the initial term. The Company paid $0.5 million during the year ended December 31, 2018 under this lease. Total remaining payments under the lease are $8.1 million.

Reorganization Transactions

In conjunction with the Reorganization, the Company entered into a tax matters agreement (“TMA”) with Riviera. SeeNote 13 – Income Taxesfor further discussion of the TMA and the related payable to Riviera.

Also in conjunction with the Reorganization, the Company paid certain legal costs incurred by Riviera on the Company’s behalf. These costs totaled $1.8 million and were included in general and administrative expenses in the accompanying consolidated statement of operations for the year ended December 31, 2018.

Consulting Services

Atlas, LLC (“Atlas”) provided the Company supervisory services throughout drilling and completion operations. Atlas is wholly owned jointly by a director and an employee of Citizen. For the year ended December 31, 2017, the Company incurred $2.3 million in charges related to services provided which are recorded within oil and natural gas properties, successful efforts on the accompanying consolidated balance sheet. As of December 31, 2017, the Company had no amounts payable to Atlas. There were no such services provided by Atlas to the Company during the year ended December 31, 2018.

Note 13 – Income Taxes

As discussed inNote 1 – Business and Organization, the Company was formed in September 2018 in connection with the Reorganization. The Company’s accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of its members.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

A deferred tax liability was recorded as a result of the Reorganization based on the Company becoming a corporation that is a taxable entity under the Internal Revenue Code of 1986, as amended (the “Code”). The initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization was reflected in income tax expense based on the deferred tax liability resulting from the change in tax status. Due to the nontaxable nature of the Reorganization, there were no adjustments to the tax basis or other tax attributes in the measurement of the deferred taxes except to the extent any gain was recognized by the other parties to the Reorganization.

The Company’s effective combined U.S. federal and state income tax rate for the year ended December 31, 2018 excluding discrete items was 24.3%. During the year ended December 31, 2007,2018, the Company granted an aggregate 150,000 unit warrantsrecognized income tax expense of $356.9 million, including $304.5 million related to the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization.

In conjunction with the Reorganization, the Company entered into the TMA with Riviera. The TMA, in part, provides for the indemnification of the Company and the entitlement of Riviera to refunds related to certain individuals in connection withtaxes of Linn Energy, Inc. prior to the spinoff of assets from Linn Energy, Inc. to Riviera. As a result of the TMA and an acquisition transition services agreement. The unit warrants, allestimated overpayment of which remain outstanding, have an exercise pricefederal taxes by Linn Energy, Inc. received by the Company, the Company recorded a payable of $25.50 per unit warrant, are fully exercisable$7.6 million to Riviera at December 31, 2011,2018. The payable is included in accounts payable and expire 10 years fromaccrued liabilities – affiliates in the date of issuance.accompanying consolidated balance sheets.

Defined Contribution PlanAt December 31, 2018, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax year for 2018 remains subject to examination by the major tax jurisdictions.

The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100%components of the first 4% of eligible compensation contributed by the employee on a before-tax basisCompany’s provision for income taxes for the year ending December 31, 2009. For the years ended December 31, 2011,2018 are as follows (in thousands):

Current income tax expense

  

Federal

  $—   

State

   —   
  

 

 

 
   —   

Deferred income tax expense

  

Federal

   277,794 

State

   79,068 
  

 

 

 
   356,862 
  

 

 

 

Provision for income taxes

  $356,862 
  

 

 

 

The Company’s deferred tax assets and liabilities as of December 31, 2010,2018 include the Company contribution was equalfollowing (in thousands):

Deferred income tax assets

  

Net operating losses

  $42,013 

Other

   4,409 
  

 

 

 
   46,422 

Deferred income tax liabilities

  

Oil and natural gas properties

   (377,362

Derivative contracts

   (25,922
  

 

 

 
   (403,284
  

 

 

 

Deferred tax liabilities, net

  $(356,862
  

 

 

 

Roan Resources, Inc.

Notes to 100%Consolidated Financial Statements

The following is a reconciliation, stated as a percentage of pretax income, of the first 6% of eligible employee compensation. The Company contributed approximately $4 million, $3 million and $2 million duringUnited States statutory federal income tax rate to the yearsCompany’s effective tax rate for the year ended December 31, 2011,2018:

   Amount   Percent 
   (in thousands) 

Income (loss) at U.S. federal statutory rate

  $45,400    21.0

Net effect of state income taxes

   9,173    4.2

Change in tax status

   304,455    140.8

Other

   (2,166   (1.0)% 
  

 

 

   

 

 

 

Income tax provision / Effective rate

  $356,862    165.0
  

 

 

   

 

 

 

As of December 31, 2010,2018, the Company has federal and December 31, 2009, respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalfOklahoma net operating loss carryforwards for both jurisdictions of the plan participants.$165.0 million, which do not expire.

Index to Financial Statements

LINN ENERGY, LLCNote 14 – Commitments and Contingencies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Note 6—DebtCommitments

The following summarizes debt outstanding:table presents the future minimum payments under noncancelable operating leases and other commitments as of December 31, 2018 (in thousands):

 

   December 31, 2011  December 31, 2010 
   Carrying
Value
  Fair
Value(1)
   Interest
Rate(2)
  Carrying
Value
  Fair
Value(1)
   Interest
Rate(2)
 
   (in millions, except percentages) 

Credit facility

  $940   $940     2.57 $—     $—       —    

11.75% senior notes due 2017

   41    46     12.73  250    288     12.73

9.875% senior notes due 2018

   14    16     10.25  256    279     10.25

6.50% senior notes, due 2019

   750    742     6.62  —      —       —    

8.625% senior notes due 2020

   1,300    1,406     9.00  1,300    1,396     9.00

7.75% senior notes due 2021

   1,000    1,036     8.00  1,000    1,021     8.00

Less current maturities

   —      —        —      —      
  

 

 

  

 

 

    

 

 

  

 

 

   
   4,045   $4,186      2,806   $2,984    
   

 

 

     

 

 

   

Unamortized discount

   (51     (63   
  

 

 

     

 

 

    

Total debt, net of discount

  $3,994      $2,743     
  

 

 

     

 

 

    
   2019   2020   2021   2022   2023   Thereafter   Total 

Office building leases

  $1,692   $2,047   $2,136   $2,229   $456   $171   $8,731 

Pipe and equipment purchase commitments (1)

   1,455    —      —      —      —      —      1,455 

Drilling rig commitments (2)

   15,352    —      —      —      —      —      15,352 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $18,499   $2,047   $2,136   $2,229   $456   $171   $25,538 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)The carrying value

Reflects commitments to purchase specified amounts of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.pipe and equipment.

(2)Represents variable interest rate for

Reflects future minimum drilling fees including early termination fees as specified by the Credit Facility and effective interest rates for the senior notes.contract.

Credit FacilityOffice building leases

On May 2, 2011, the Company entered into a Fifth Amended and Restated Credit Agreement (“Credit Facility”), which provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount of $1.5 billion. In October 2011, as part of the semi-annual redetermination, a borrowing base of $3.0 billion was approved by the lenders with the maximum commitment amount remaining unchanged at $1.5 billion. The maturity date is April 2016.

During 2011, in connection with amendments to its Credit Facility, the Company incurred financing fees and expenses of approximately $4 million, which will be amortized over the life of the Credit Facility. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations. At December 31, 2011, available borrowing capacity under the Credit Facility was $556 million, which includes a $4 million reduction in availability for outstanding letters of credit.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as upon requested interim redeterminations, by the lenders at their sole discretion. The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the Credit Facility are secured by mortgages on its and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries. The Company and its subsidiaries are required to maintain the mortgages on properties representing at least 80% of the total value of its and its subsidiaries’ oil and natural gas properties. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum equal to 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The Company is in compliance with all financial and other covenants of the Credit Facility.

Senior Notes Due 2019

On May 13, 2011, the Company issued $750 million in aggregate principal amount of 6.50% senior notes due 2019 (the “2019 Senior Notes”) at a price of 99.232%. The 2019 Senior Notes were sold to a group of initial purchasers and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds of approximately $729 million (after deducting the initial purchasers’ discount and offering expenses). The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, fund or partially fund acquisitions and for general corporate purposes. In connection with the 2019 Senior Notes, the Company incurred financing fees and expenses of approximately $15 million, which will be amortized over the life of the 2019 Senior Notes. The discount on the 2019 Senior Notes, which totaled approximately $6 million, will also be amortized over the life of the 2019 Senior Notes. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

The 2019 Senior Notes were issued under an indenture dated May 13, 2011 (“2019 Indenture”), mature May 15, 2019, and bear interest at 6.50%. Interest is payable semi-annually on May 15 and November 15, beginning November 15, 2011. The 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries has guaranteed the 2019 Senior Notes on a senior unsecured basis. The 2019 Indenture provides that the Company may redeem: (i) on or prior to May 15, 2014, up to 35% of the aggregate principal amount of the 2019 Senior Notes at a redemption price of 106.50% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to May 15, 2015, all or part of the 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the 2019 Indenture) and accrued and unpaid interest; and (iii) on or after May 15, 2015, all or part of the 2019 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The 2019 Indenture also provides that, if a change of control (as defined in the 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2019 Indenture contains covenants substantially similar to those under the Company’s 2010 Issued Senior Notes and Original Senior Notes, as defined below, that, among other things, limit the Company’s ability to: (i) pay distributions, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of the 2019 Senior Notes.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

In connection with the issuance and sale of the 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“2019 Registration Rights Agreement”) with the initial purchasers. Under the 2019 Registration Rights Agreement, the Company agreed to use reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the 2019 Senior Notes in exchange for outstanding 2019 Senior Notes within 400 days after the notes were issued. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2019 Senior Notes. If the Company fails to satisfy these obligations, the Company may be required to pay additional interest to holders of the 2019 Senior Notes under certain circumstances.

Senior Notes Due 2020 and Senior Notes Due 2021

On April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”). On September 13, 2010, the Company issued $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”). The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the 2019 Senior Notes.

Senior Notes Due 2017 and Senior Notes Due 2018

The Company also has $41 million (originally $250 million)leases its corporate office space in aggregate principal amountOklahoma City, Oklahoma from a subsidiary of 11.75% senior notes due 2017 (the “2017 Senior Notes”)Riviera. This lease began in 2018 and $14 million (originally $256 million)expires in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Senior Notes” and together2023. The Company leases additional office space from unrelated third parties for its field locations in Oklahoma.

Rent expense with the 2017 Senior Notes, the “Original Senior Notes”). The indentures relatedrespect to the Original Senior Notes originally contained redemption provisions and covenants that were substantially similar to those of the 2010 Issued Senior Notes; however, in connection with the tender offers described below, the indentures were amended and most of the covenants and certain default provisions were eliminated.

Redemptions of Original Senior Notes

In March 2011, in accordance with the provisions of the indentures related to the 2017 Senior Notes and the 2018 Senior Notes, the Company redeemed 35%, or $87 million and $90 million, respectively, of each of its original aggregate principal amount of the 2017 Senior Notes and 2018 Senior Notes. After the redemptions, $163 million and $166 million, respectively, of the 2017 Senior Notes and 2018 Senior Notes remained outstanding.

Tender Offers for and Repurchase of Original Senior Notes

On February 28, 2011, the Company commenced cash tender offers (“Offers”) and related consent solicitations to purchase any and all of its outstanding 2017 Senior Notes and 2018 Senior Notes. The Offers expired on March 25, 2011. Holders who validly tendered 2017 Senior Notes and 2018 Senior Notes on or before March 14, 2011, received total consideration of $1,212.50 and $1,172.50, respectively, for each $1,000 principal amount of such notes accepted for purchase. Total consideration included a consent payment of $30.00 per $1,000 principal amount of notes accepted for purchase. Holders who validly tendered 2017 Senior Notes and 2018 Senior Notes after March 14, 2011, but before March 25, 2011, received $1,182.50 and $1,142.50, respectively, for each $1,000 principal amount of such notes accepted for purchase.

In March 2011, in connection with its Offers and related consent solicitations, the Company accepted and purchased: 1) $105 million of the aggregate principal amount of its outstanding 2017 Senior Notes (or 65% of the remaining outstanding principal amount of its 2017 Senior Notes), and 2) $126 million of the aggregate principal amount of its outstanding 2018 Senior Notes (or 76% of the remaining outstanding principal amount of its 2018 Senior Notes).

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

In conjunction with each tender offer, the Company received consents to amendments to the indentures of the 2017 Senior Notes and 2018 Senior Notes, which eliminated most of the covenants and certain default provisions applicable to the series of notes issued under such indentures. The amendments became effective upon the execution of the supplemental indentures to the indentures governing each of the 2017 Senior Notes and the 2018 Senior Notes.

In June 2011, the Company repurchased an additional portion of its remaining outstanding 2017 Senior Notes and 2018 Senior Notes forthese lease commitments was approximately $17 million (or 29% of the remaining outstanding principal amount of its 2017 Senior Notes) and approximately $24 million (or 61% of the remaining outstanding principal amount of its 2018 Senior Notes), respectively. In December 2011, the Company also repurchased an additional portion of its remaining outstanding 2018 Senior Notes for approximately $2 million (or 9% of the remaining outstanding principal amount of its 2018 Senior Notes). After giving effect to the tender offers and subsequent repurchases of the 2017 Senior Notes and the 2018 Senior Notes, aggregate principal amounts of $41 million and $14 million, respectively, remain outstanding at December 31, 2011.

In connection with the redemptions, cash tender offers and additional repurchases of a portion of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $95$1.4 million for the year ended December 31, 2011.2018.

Note 7—DerivativesDrilling Contracts

Commodity Derivatives

The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. AtAs of December 31, 2011,2018, the Company had no outstanding collars. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

The following table summarizes open positions as of December 31, 2011, and represents, as of such date, derivatives in place through December 31, 2016, on annual production volumes:

   2012  2013  2014  2015  2016 

Natural gas positions:

      

Fixed price swaps:

      

Hedged volume (MMMBtu)

   56,730    64,367    73,456    82,490    2,745  

Average price ($/MMBtu)

  $5.85   $5.69   $5.69   $5.75   $5.00  

Puts:

      

Hedged volume (MMMBtu)

   38,357    37,340    30,660    32,850    —    

Average price ($/MMBtu)

  $5.83   $5.85   $5.00   $5.00   $—    

Total:

      

Hedged volume (MMMBtu)

   95,087    101,707    104,116    115,340    2,745  

Average price ($/MMBtu)

  $5.84   $5.75   $5.49   $5.54   $5.00  

Oil positions:

      

Fixed price swaps:(1)

      

Hedged volume (MBbls)

   8,171    9,033    9,034    9,581    —    

Average price ($/Bbl)

  $97.37   $98.05   $95.39   $98.25   $—    

Puts:

      

Hedged volume (MBbls)

   2,196    2,300    —      —      —    

Average price ($/Bbl)

  $100.00   $100.00   $—     $—     $—    

Total:

      

Hedged volume (MBbls)

   10,367    11,333    9,034    9,581    —    

Average price ($/Bbl)

  $97.93   $98.44   $95.39   $98.25   $—    

Natural gas basis differential positions:

      

PEPL basis swaps:(2)

      

Hedged volume (MMMBtu)

   37,735    38,854    42,194    42,194    —    

Hedged differential ($/MMBtu)

  $(0.89 $(0.89 $(0.39 $(0.39 $—    

Oil timing differential positions:

      

Trade month roll swaps:(3)

      

Hedged volume (MBbls)

   5,982    6,315    6,315    840    —    

Hedged differential ($/Bbl)

  $0.21   $0.21   $0.21   $0.17   $—    

(1)As presented in the table above, the Company has certain outstanding fixed price oil swaps on 14,750 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2016, December 31, 2017, and December 31, 2018, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
(2)Settle on the Panhandle Eastern Pipeline (“PEPL”) spot price of natural gas to hedge basis differential associated with natural gas production in the Mid-Continent Deep and Mid-Continent Shallow regions.
(3)The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent Deep, Mid-Continent Shallow and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

During the year ended December 31, 2011, the Company entered into commodity derivativedrilling rig contracts consisting of oil and natural gas swaps for certain years through 2016 and oil trade month roll swaps for October 2011 through December 2015. In September 2011, the Company canceled its oil and natural gas swaps for the year 2016 and used the realized gains of approximately $27 million to increase prices on its existing oil and natural gas swaps for the year 2012. Also, in September 2011, the Company paid premiums of approximately $33 million to increase prices on its existing oil puts for the years 2012 and 2013. In addition, during the fourth quarter of 2011, the Company paid premiums of approximately $52 million for put options and approximately $22 million to increase prices on its existing oil puts for 2012 and 2013, respectively.

Settled derivatives on natural gas production for the year ended December 31, 2011, included volumes of 64,457 MMMBtu at an average contract price of $8.24. Settled derivatives on oil production for the year ended December 31, 2011, included volumes of 7,917 MBbls at an average contract price of $85.70. Settled derivatives on natural gas production for the year ended December 31, 2010, included volumes of 57,160 MMMBtu at an average contract price of $8.66. Settled derivatives on oil production for the year ended December 31, 2010, included volumes of 4,650 MBbls at an average contract price of $99.68. The natural gas derivatives are settled based on the closing NYMEX future price of natural gas or the published PEPL spot price of natural gas on the settlement date, which occurs on thewith various third day preceding the production month. The oil derivatives are settled based on the month’s average daily NYMEX price of light crude oil and settlement occurs on the final day of the production month.

Interest Rate Swaps

The Company may from time to time enter into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparty the difference, and conversely, the counterparty is required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company does not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.

In April 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of the 2020 Senior Notes (see Note 6). In conjunction with the repayment of borrowings under its Credit Facility with proceeds from the issuance of 2020 Senior Notes, the Company canceled (before the contract settlement date) certain interest rate swap agreements for 2010 through 2013, resulting in realized losses of approximately $74 million. In September 2010, the Company canceled (before the contract settlement date) all of its remaining interest rate swap agreements in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of 2021 Senior Notes (see Note 6). The cancellation of the interest rate swap agreements in September 2010 resulted in a realized loss of approximately $50 million. At December 31, 2011, and December 31, 2010, the Company had no outstanding interest rate swap agreements.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Balance Sheet Presentation

The Company’s commodity derivatives and, when applicable, its interest rate swap derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:

   December 31, 
   2011   2010 
   (in thousands) 

Assets:

    

Commodity derivatives

  $880,175    $637,836  
  

 

 

   

 

 

 

Liabilities:

    

Commodity derivatives

  $320,835    $398,902  
  

 

 

   

 

 

 

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, when applicable, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $880 million at December 31, 2011. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives and, when applicable, its interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives, including realized and unrealized gains and losses, are reported on the consolidated statements of operations in “gains (losses) on oil and natural gas derivatives” and “losses on interest rate swaps.” Realized gains (losses), excluding canceled derivatives, represent amounts related to the settlement of derivative instruments, and for commodity derivatives, are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

The following presents the Company’s reported gains and losses on derivative instruments:

   Year Ended December 31, 
   2011   2010  2009 
   (in thousands) 

Realized gains (losses):

     

Commodity derivatives

  $230,237    $307,587   $400,968  

Interest rate swaps

   —       (8,021  (42,881

Canceled derivatives

   26,752     (123,865  48,977  
  

 

 

   

 

 

  

 

 

 
  $256,989    $175,701   $407,064  
  

 

 

   

 

 

  

 

 

 

Unrealized gains (losses):

     

Commodity derivatives

  $192,951    $(232,376 $(591,379

Interest rate swaps

   —       63,978    16,588  
  

 

 

   

 

 

  

 

 

 
  $192,951    $(168,398 $(574,791
  

 

 

   

 

 

  

 

 

 

Total gains (losses):

     

Commodity derivatives

  $449,940    $75,211   $(141,374

Interest rate swaps

   —       (67,908  (26,353
  

 

 

   

 

 

  

 

 

 
  $449,940    $7,303   $(167,727
  

 

 

   

 

 

  

 

 

 

During the year ended December 31, 2011, the Company canceled (before the contract settlement date) its oil and natural gas swaps for the year 2016 and used the realized gains of approximately $27 million to increase prices on its existing oil and natural gas swaps for the year 2012. During the year ended December 31, 2010, the Company canceled (before the contract settlement date) all of its interest rate swap agreements resulting in realized losses of approximately $124 million.

During the year ended December 31, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized net gains of approximately $49 million. Of this amount, realized net gains of approximately $45 million, along with an incremental premium payment of approximately $49 million, were used to reposition the Company’s commodity derivative portfolio in July 2009, when the Company canceled oil and natural gas derivative contracts for years 2012 through 2014 to raise prices for oil and natural gas derivative contracts in years 2010 and 2011.

Note 8—Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives and, when applicable, its interest rate derivatives at fair value (see Note 7) on a recurring basis. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives and, when applicable, its interest rate derivatives.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Fair Value Hierarchy

In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1

Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

Level 2

Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives and interest rate swaps).

Level 3

Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

   Fair Value Measurements on a Recurring Basis
December 31, 2011
 
           Level 2                   Netting(1)                  Total         
   (in thousands) 

Assets:

     

Commodity derivatives

  $880,175    $(303,272 $576,903  

Liabilities:

     

Commodity derivatives

  $320,835    $(303,272 $17,563  

(1)Represents counterparty netting under agreements governing such derivatives.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Note 9—Other Property and Equipment

Other property and equipment consists of the following:

   December 31, 
   2011  2010 
   (in thousands) 

Natural gas compression plant and pipeline

  $129,863   $96,624  

Buildings and leasehold improvements

   16,158    10,874  

Vehicles

   13,653    10,127  

Drilling and other equipment

   3,645    1,827  

Furniture and office equipment

   29,972    17,529  

Land

   3,944    2,922  
  

 

 

  

 

 

 
   197,235    139,903  

Less accumulated depreciation

   (48,024  (35,151
  

 

 

  

 

 

 
  $149,211   $104,752  
  

 

 

  

 

 

 

Note 10—Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for each of the years in the three-year period ended December 31, 2011); and (iv) a credit-adjusted risk-free interest rate (average of 7.5%, 8.6% and 9.6% for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively).

The following presents a reconciliation of the Company’s asset retirement obligations:

   December 31, 
   2011  2010 
   (in thousands) 

Asset retirement obligations at beginning of year

  $42,945   $33,135  

Liabilities added from acquisitions

   19,853    6,976  

Liabilities added from drilling

   1,277    309  

Current year accretion expense

   4,140    2,694  

Settlements

   (2,218  (169

Revision of estimates

   5,145    —    
  

 

 

  

 

 

 

Asset retirement obligations at end of year

  $71,142   $42,945  
  

 

 

  

 

 

 

Note 11—Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits and is involved in various other disputes arising in the ordinary course of business including claims from royalty owners related to disputed royalty paymentsensure rig availability to complete the Company’s drilling projects. These commitments are not recorded in the accompanying consolidated balance sheets.

Purchase Commitments

As of December 31, 2018, the Company had entered into pipeline and royalty valuations. The Company has established reserves that management currently believesequipment purchase commitments with various third parties in the ordinary course of business to purchase specified amounts of pipe and equipment. These commitments are not recorded in the accompanying consolidated balance sheets.

Index

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

 

adequate to provide for potential liabilities based upon its evaluationLitigation

In the ordinary course of these matters. For a certain statewide class action royalty payment dispute where a reserve has not yet been established,business, the Company has denied that it has any liability on themay at times be subject to claims and has raised arguments and defenseslegal actions. Management believes it is remote that if accepted by the court,impact of such matters will result in no loss to the Company. Discovery in this dispute is ongoing and is not complete. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business,the Company’s financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.flows.

On September 15, 2008, and October 3, 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”), respectively, filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. At December 31, 2011, and December 31, 2010, the Company had a net receivable of approximately $7 million from Lehman Commodity Services related to canceled derivative contracts, which is included in “other current assets” on the consolidated balance sheets. The value of the receivable was estimated based on market expectations. In March 2011, the Company, Lehman Holdings and Lehman Commodity Services entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman Holdings and Lehman Commodity Services in the amount of $51 million each, provided that the aggregate value of the distributions to the Company on account of both such claims will not exceed $51 million (collectively, the “Company Claim”). On December 6, 2011, a Chapter 11 Plan (“Plan”) was approved by the Bankruptcy Court. Initial distributions under the Plan to creditors, including the Company, are expected to occur after January 31, 2012. Based on the recovery estimates described in the approved disclosure statement relating to the Plan, the Company expects to ultimately receive a substantial portion of the Company Claim.

Note 12—Earnings Per Unit

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for income (loss) from continuing operations:

   Income (Loss)
(Numerator)
  Units
(Denominator)
   Per Unit
Amount
 
   (in thousands)     

Year ended December 31, 2011:

     

Income from continuing operations:

     

Allocated to units

  $438,439     

Allocated to unvested restricted units

   (4,739   
  

 

 

    
  $433,700     
  

 

 

    

Income per unit:

     

Basic income per unit

    172,004    $2.52  

Dilutive effect of unit equivalents

    725     (0.01
   

 

 

   

 

 

 

Diluted income per unit

    172,729    $2.51  
   

 

 

   

 

 

 

Year ended December 31, 2010:

     

Loss from continuing operations:

     

Allocated to units

  $(114,288   

Allocated to unvested restricted units

   —       
  

 

 

    
  $(114,288   
  

 

 

    

Loss per unit:

     

Basic loss per unit

    142,535    $(0.80

Dilutive effect of unit equivalents

    —       —    
   

 

 

   

 

 

 

Diluted loss per unit

    142,535    $(0.80
   

 

 

   

 

 

 

Year ended December 31, 2009:

     

Loss from continuing operations:

     

Allocated to units

  $(295,841   

Allocated to unvested restricted units

   —       
  

 

 

    
  $(295,841   
  

 

 

    

Loss per unit:

     

Basic loss per unit

    119,307    $(2.48

Dilutive effect of unit equivalents

    —       —    
   

 

 

   

 

 

 

Diluted loss per unit

    119,307    $(2.48
   

 

 

   

 

 

 

There were no anti-dilutive unit equivalents for the year ended December 31, 2011. Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 2 million unit options and warrants for each of the years ended December 31, 2010, and December 31, 2009. All equivalent units were anti-dilutive for the years ended December 31, 2010, and December 31, 2009, respectively.

Note 13—Operating Leases

The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2019. The Company recognized expense under operating leases of approximately $5 million, $5 million, and $4 million, for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

As of December 31, 2011, future minimum lease payments were as follows (in thousands):

2012

  $5,652  

2013

   4,769  

2014

   4,598  

2015

   4,455  

2016

   2,950  

Thereafter

   9,053  
  

 

 

 
  $31,477  
  

 

 

 

Note 14—Income TaxesEnvironmental Matters

The Company is a limited liability company treated as a partnership forsubject to various federal, state and state income tax purposes, withlocal laws and regulations relating to the exceptionprotection of the statesenvironment. These laws, which are often changing, regulate the discharge of Texasmaterials into the environment and Michigan, with income tax liabilities and/may require the Company to remove or benefitsmitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company passed through to its unitholders. Limited liability companies are subject to state income taxes in Texas and Michigan and certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the states of Texas and Michigan and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxesestablished procedures for the ongoing evaluation of its operations of the Company, except as set forth in the tables below.

The Company’s taxable income or loss, which may vary substantially from the net income or net loss reported in the consolidated statements of operations, is includable in the federalto identify potential environmental exposures and state income tax returns of each unitholder. The aggregate difference in the basis of net assets for financialto comply with regulatory policies and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholder’s tax attributes.

Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax benefit (expense) from continuing operations consisted of the following:

   Year Ended December 31, 
   2011  2010  2009 
   (in thousands) 

Current taxes:

    

Federal

  $(4,551 $(65 $(1,063

State

   (605  (1,088  (678

Deferred taxes:

    

Federal

   1,148    (2,862  5,307  

State

   (1,458  (226  655  
  

 

 

  

 

 

  

 

 

 
  $(5,466 $(4,241 $4,221  
  

 

 

  

 

 

  

 

 

 

As of December 31, 2011, the Company’s taxable entities had approximately $8 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2031.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Income tax benefit (expense) differed from amounts computed by applying the federal income tax rate of 35% to pre-tax income (loss) from continuing operations as a result of the following:

   Year Ended December 31, 
   2011  2010  2009 

Federal statutory rate

   35.0  35.0  35.0

State, net of federal tax benefit

   0.5    (1.2  —    

Loss excluded from nontaxable entities

   (34.4  (37.5  (34.3

Other items

   0.1    (0.1  0.7  
  

 

 

  

 

 

  

 

 

 

Effective rate

   1.2  (3.8)%   1.4
  

 

 

  

 

 

  

 

 

 

Significant components of the deferred tax assets and liabilities were as follows:

   December 31, 
   2011  2010 
   (in thousands) 

Deferred tax assets:

   

Net operating loss carryforwards

  $159   $717  

Unit-based compensation

   9,146    6,234  

Other

   3,606    3,513  

Valuation allowance

   —      (217
  

 

 

  

 

 

 

Total deferred tax assets

   12,911    10,247  
  

 

 

  

 

 

 

Deferred tax liabilities:

   

Other accruals

   —      (2,755

Property and equipment principally due to differences in depreciation

   (8,226  (4,323

Other

   (1,646  179  
  

 

 

  

 

 

 

Total deferred tax liabilities

   (9,872  (6,899
  

 

 

  

 

 

 

Net deferred tax assets

  $3,039   $3,348  
  

 

 

  

 

 

 

Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:

   December 31, 
   2011  2010 
   (in thousands) 

Deferred tax assets

  $8,279   $5,265  

Deferred tax liabilities

   (589  (3,105
  

 

 

  

 

 

 

Other current assets

  $7,690   $2,160  
  

 

 

  

 

 

 

Deferred tax assets

  $4,632   $4,982  

Deferred tax liabilities

   (9,283  (3,794
  

 

 

  

 

 

 

Other noncurrent assets (liabilities)

  $(4,651 $1,188  
  

 

 

  

 

 

 

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.procedures. At December 31, 2011, based upon2018 and 2017, the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

In accordance with the applicable accounting standard, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy in identifying uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2011, and December 31, 2010.environmental matters requiring specific disclosure or requiring the recognition of a liability.

Note 15—Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows

“Other accrued liabilities” reported on the consolidated balance sheets include the following:

   December 31, 
   2011   2010 
   (in thousands) 

Accrued compensation

  $19,581    $18,931  

Accrued interest

   55,170     62,999  

Other

   1,147     509  
  

 

 

   

 

 

 
  $75,898    $82,439  
  

 

 

   

 

 

 

Supplemental disclosures to the consolidated statements of cash flows are presented below:

   Year Ended December 31, 
   2011  2010  2009 
   (in thousands) 

Cash payments for interest, net of amounts capitalized

  $247,217   $128,807   $73,861  
  

 

 

  

 

 

  

 

 

 

Cash payments for income taxes

  $487   $1,797   $1,282  
  

 

 

  

 

 

  

 

 

 

Noncash investing activities:

    

In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follow:

    

Fair value of assets acquired

  $1,523,466   $1,375,010   $117,717  

Cash paid

   (1,500,193  (1,351,033  (115,285

Receivable from seller

   3,557    9,976    636  

Payables to sellers

   (4,847  —      —    
  

 

 

  

 

 

  

 

 

 

Liabilities assumed

  $21,983   $33,953   $3,068  
  

 

 

  

 

 

  

 

 

 

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $4 million and $3 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2011, and December 31, 2010, respectively, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.Natural Gas Dedication Agreements

The Company manageshas dedicated its working capital and cash requirements to borrow only as needednatural gas production from its Credit Facility. At December 31, 2011, approximately $54 million was included in “accounts payable and accrued expenses” on the consolidated balance sheet which represents reclassified net outstanding checks. There was no such balance at December 31, 2010. The Company presents these net outstanding checks as cash flows from financing activities on the consolidated statements of cash flows.

Note 16—Subsidiary Guarantors

The 2019 Senior Notes, the 2010 Issued Notes and the Original Senior Notes are guaranteed by all of the Company’s material subsidiaries. The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

Index to Financial Statements

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)

The following discussion and analysis should be read in conjunction with LINN’s historical audited financial statements. The Company’s Appalachian Basin and Mid Atlantic operations are classified as discontinued operations on the consolidated statements of operations for the period ended December 31, 2009 (see Note 2). Where applicable, the following supplemental oil and natural gas data present continuing operations separatelyproperties contributed by Citizen under an agreement with a third party. Under this dedication agreement, the Company is required to deliver its natural gas production from discontinued operations.the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.

For the oil and natural gas properties contributed by Linn, the Company assumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.

Volume Commitment

Under an agreement with a third party, the Company has a requirement to deliver a minimum volume of natural gas from a specified area, as defined in the agreement. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees on any undelivered volumes as of November 2021. If the Company is unable to deliver any natural gas volumes subsequent to December 31, 2018 through November 2021, it will owe deficiency fees of $8.1 million at the end of the commitment period.

Note 15 – Subsequent Events

In January 2019, the Company entered into a water management services agreement with Blue Mountain. Under this agreement, Blue Mountain will provide water management services including pipeline gathering, disposal, treatment and redelivery of recycled water. The agreement provides for an acreage dedication for water management services through January 2029.

In March 2019, the Company amended its 2017 Credit Facility to, among other things, increase its borrowing base to $750 million.

Subsequent to December 31, 2018, the Company entered into fixed price swaps of 40,000 MMBtu per day of natural gas production at a weighted average price of $2.68 for the period of October 2020 through December 2020 and for 2,000 Bbls per day of oil production at a weighted average price of $57.80 for the period of January 2020 through December 2020.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

Note 16. Supplemental Information on Oil and Natural Gas Operations (Unaudited)

The following disclosures provide supplemental unaudited information regarding the Company’s oil, natural gas and NGL activities, which were entirely within the United States.

Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:

   December 31, 
   2018   2017 
   (in thousands) 

Oil and natural gas properties

    

Proved properties

  $1,538,379   $750,492 

Unproved properties

   1,089,954    1,126,459 
  

 

 

   

 

 

 

Total oil and natural gas properties

   2,628,333    1,876,951 

Accumulated depreciation, depletion, amortization and impairment

   (230,836   (78,307
  

 

 

   

 

 

 

Oil and natural gas properties, net

  $2,397,497   $1,798,644 
  

 

 

   

 

 

 

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in oil, and natural gas and NGL property acquisition, exploration and development whether capitalized or expensed,activities are presented below:summarized as follows:

 

   Year Ended December 31, 
   2011   2010   2009 
   (in thousands) 

Property acquisition costs:(1)

      

Proved

  $1,328,328    $1,290,826    $115,929  

Unproved

   188,409     65,604     947  

Exploration costs

   80     74     337  

Development costs

   639,395     244,834     140,521  

Asset retirement costs

   2,427     748     371  
  

 

 

   

 

 

   

 

 

 

Total costs incurred

  $2,158,639    $1,602,086    $258,105  
  

 

 

   

 

 

   

 

 

 
   December 31, 
   2018   2017   2016 
   (in thousands) 

Acquisition costs of properties

      

Proved properties

  $5,655   $214,647   $1,079 

Unproved properties

   42,738    1,018,978    93,705 

Development costs

   719,198    390,991    152,284 

Exploratory(1)

   7,257    8,538    —   
  

 

 

   

 

 

   

 

 

 

Total costs incurred

  $774,848   $1,633,154   $247,068 
  

 

 

   

 

 

   

 

 

 

 

(1)See Note 2 for details about the Company’s acquisitions.

Includes seismic costs.

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related

Roan Resources, Inc.

Notes to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

   December 31, 
   2011  2010 
   (in thousands) 

Proved properties:

   

Leasehold acquisition

  $6,040,239   $4,695,704  

Development

   1,484,486    840,175  

Unproved properties

   310,925    128,624  
  

 

 

  

 

 

 
   7,835,650    5,664,503  

Less accumulated depletion and amortization

   (1,033,617  (719,035
  

 

 

  

 

 

 
  $6,802,033   $4,945,468  
  

 

 

  

 

 

 

Index toConsolidated Financial Statements

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)—Continued

 

Results of Operations for Oil, and Natural Gas and NGL Producing Activities

The following table sets forth the Company’s results of operations for oil, natural gas and NGL producing activities (excluding corporate overheadfor the years ended December 31, 2018, 2017 and interest costs) are presented below:2016:

 

   Year Ended December 31, 
   2011  2010   2009 
   (in thousands) 

Revenues and other:

     

Oil, natural gas and natural gas liquid sales

  $1,162,037   $690,054    $408,219  

Gains (losses) on oil and natural gas derivatives

   449,940    75,211     (141,374
  

 

 

  

 

 

   

 

 

 
   1,611,977    765,265     266,845  
  

 

 

  

 

 

   

 

 

 

Production costs:

     

Lease operating expenses

   232,619    158,382     132,647  

Transportation expenses

   28,358    19,594     18,202  

Severance and ad valorem taxes

   78,458    45,114     28,687  
  

 

 

  

 

 

   

 

 

 
   339,435    223,090     179,536  
  

 

 

  

 

 

   

 

 

 

Other costs:

     

Exploration costs

   2,390    5,168     7,169  

Depletion and amortization

   320,096    226,552     191,314  

Impairment of long-lived assets

   —      38,600     —    

Texas margin tax expense

   1,599    657     490  

Gains on sale of assets and other, net

   (1,001  —       (25,710
  

 

 

  

 

 

   

 

 

 
   323,084    270,977     173,263  
  

 

 

  

 

 

   

 

 

 

Results of continuing operations

  $949,458   $271,198    $(85,954
  

 

 

  

 

 

   

 

 

 

Results of discontinued operations

  $—     $—      $(238
  

 

 

  

 

 

   

 

 

 

There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to state income taxes in Texas and Michigan (see Note 14). Discontinued operations for 2009 primarily represent activity related to post-closing adjustments for the sale of properties in the Appalachian Basin in 2008 (see Note 2).

Index to Financial Statements

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)—Continued

   Years Ended December 31, 
   2018   2017   2016 
   (in thousands) 

Oil, natural gas and NGL sales

  $439,767   $166,385   $54,965 

Production expenses

   47,600    16,872    5,090 

Production taxes

   17,579    3,685    1,087 

Exploration expenses

   43,303    28,154    —   

Gathering, transportation and processing (1)

   —      18,602    5,920 

Depreciation, depletion, amortization, and accretion

   123,062    37,376    24,996 

Impairment

   —      4,475    5,258 

Income tax expense (2)

   13,103    —      —   
  

 

 

   

 

 

   

 

 

 

Results of operations

  $195,120   $57,221   $12,614 
  

 

 

   

 

 

   

 

 

 

 

(1)

Gathering, transportation and processing for the year ended December 31, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

(2)

Income tax expense is calculated using results from the period after the Reorganization when the Company became a taxable entity and the Company’s effective tax rate of 24.3%.

Proved Oil, Natural Gas and NGL Reserves

The provedProved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based uponthe 12-month unweighted average of the first day of the month prices. Proved reserves are estimated volumes of oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent

Roan Resources, Inc.

Notes to Consolidated Financial Statements

in estimating quantities of proved reserves, and projecting future production rates and timing of future development costs. The following table sets forth proved reserves during the periods indicated:

   Oil (MBbls)  Natural Gas (MMcf)  NGLs (MBbls)  Total (MBoe) 

Proved reserves at December 31, 2015

   387   8,517   678   2,484 

Purchases of reserves

   22   333   33   111 

Extensions and discoveries

   2,632   33,218   2,956   11,124 

Revisions of previous estimates

   598   4,145   398   1,687 

Production

   (740  (6,382  (546  (2,350
  

 

 

  

 

 

  

 

 

  

 

 

 

Proved reserves at December 31, 2016

   2,900   39,831   3,519   13,057 

Purchases of reserves

   9,843   163,638   16,870   53,986 

Extensions and discoveries

   30,554   486,510   61,599   173,238 

Revisions of previous estimates

   (3,583  20,844   (260  (369

Production

   (2,294  (24,953  (2,150  (8,603
  

 

 

  

 

 

  

 

 

  

 

 

 

Proved reserves at December 31, 2017

   37,420   685,869   79,578   231,309 

Purchases of reserves

   —     —     —     —   

Extensions and discoveries

   34,714   451,750   48,791   158,797 

Revisions of previous estimates

   (12,087  (184,547  (25,365  (68,209

Production

   (4,364  (41,890  (4,592  (15,938
  

 

 

  

 

 

  

 

 

  

 

 

 

Proved reserves at December 31, 2018

   55,683   911,182   98,412   305,959 
  

 

 

  

 

 

  

 

 

  

 

 

 

At December 31, 2018, the Company had approximately 305,959 MBoe of proved reserves. During 2018, the Company drilled 214 gross wells. This continued development of the Company’s acreage and the drilling activity of other operators in the area with consideration of the Company’s development plan resulted in extensions and discoveries of 158,797 MBoe. Revisions of previous estimates for the year ended December 31, 2018 reflect downward revisions of 33,342 MBoe associated with production performance and downward revisions of 36,038 MBoe that resulted from reworking of the Company’s development plan, primarily driven by changes in wellbore lateral length and well density. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return. The impact of pricing on revisions of previous estimates was minimal.

At December 31, 2017, the Company had approximately 231,309 MBoe of proved reserves. During 2017, the Company acquired unproved leasehold acreage and drilled 93 gross wells. The Company’s drilling activity and the drilling activity of other operators in the area resulted in extensions and discoveries of 173,238 MBoe. Purchase of reserves of 53,986 MBoe reflects the reserves acquired in the Linn Acquisition. Revisions of previous estimates reflects upward revisions associated with increases in pricing of 3,277 MBoe, offset by downward revisions associated with performance of 3,646 MBoe. The purchase of reserves and extensions and discoveries were the primary drivers in the increase in reserves from December 31, 2016 to December 31, 2017.

At December 31, 2016, the Company had approximately 13,057 MBoe of proved reserves. During 2016, Citizen acquired approximately 62,500 net acres of unproved leasehold. Citizen’s drilling of 55 gross wells and the drilling activity of other operators in the area resulted in extensions and discoveries of 11,124 MBoe. Additionally, the Company had additions to reserves during 2016 of 111 MBoe from purchase of reserves and 1,687 MBoe as a result of revisions of previous estimates due to well performance. Extensions and discoveries were the primary driver in the increase in proved reserves from December 31, 2015 to December 31, 2016.

Roan Resources, Inc.

Notes to Consolidated Financial Statements

The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped (“PUD”) oil, natural gas and NGL reserves of the Company have been prepared by the independent engineering firm, DeGolyeras of December 31, 2018, 2017, and MacNaughton. 2016:

   December 31, 
   2018   2017   2016 

Proved Developed Reserves

      

Oil (MBbls)

   18,652    12,352    2,900 

Natural gas (MMcf)

   369,677    259,193    39,831 

NGL (MBbls)

   39,927    24,034    3,519 
  

 

 

   

 

 

   

 

 

 

Total (MBoe)

   120,192    79,585    13,057 
  

 

 

   

 

 

   

 

 

 

Proved Undeveloped Reserves

      

Oil (MBbls)

   37,031    25,068    —   

Natural gas (MMcf)

   541,505    426,676    —   

NGL (MBbls)

   58,485    55,544    —   
  

 

 

   

 

 

   

 

 

 

Total (MBoe)

   185,767    151,724    —   
  

 

 

   

 

 

   

 

 

 

Total Proved Reserves

      

Oil (MBbls)

   55,683    37,420    2,900 

Natural gas (MMcf)

   911,182    685,869    39,831 

NGL (MBbls)

   98,412    79,578    3,519 
  

 

 

   

 

 

   

 

 

 

Total (MBoe)

   305,959    231,309    13,057 
  

 

 

   

 

 

   

 

 

 

In accordance with SEC regulations, reserves at December 31, 2011, December 31, 2010, and December 31, 2009, were estimated using the average price during Company usesthe 12-month period, determinedaverage price calculated as anthe unweighted arithmetic average of the first-day-of-the-monthspot price foron the first day of each month unlesswithinthe 12-month period prior to the end of the reporting period. The oil and natural gas prices used in computing the Company’s reserves as of December 31, 2018, 2017, and 2016 were $65.66, $51.34, and $42.64 per barrel of oil, respectively, $3.16, $2.98, and $2.48 per MMBtu of natural gas, respectively. The NGL prices used in computing the Company’s reserves as of December 31, 2018, 2017, and 2016 were $20.35, $19.00, and $15.26 per barrel, respectively.

Approximately 93% of our proved reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers. Our personnel prepared reserve estimates with respect to the remaining approximate 7% of our proved reserves as of December 31, 2018. All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined by contractual arrangements, excluding escalationsas having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon future conditions. An analysisa number of factors, including many factors beyond the change in estimatedCompany’s control such as reservoir performance, prices, economic conditions, and government restrictions. In addition, results of drilling, testing, and production subsequent to the date of an estimate may justify revision of that estimate.

Reserve estimates are often different from the quantities of oil, natural gas, and NGL reserves, all of whichNGLs that are located within the U.S., is shown below:

   Year Ended December 31, 2011 
   Natural Gas
(Bcf)
  Oil
(MMBbls)
  NGL
(MMBbls)
  Total
(Bcfe)
 

Proved developed and undeveloped reserves:

     

Beginning of year

   1,233    156.4    70.9    2,597  

Revisions of previous estimates

   (71  (9.2  0.9    (121

Purchase of minerals in place

   337    39.3    1.0    579  

Extensions, discoveries and other additions

   240    10.3    24.6    450  

Production

   (64  (7.8  (3.9  (135
  

 

 

  

 

 

  

 

 

  

 

 

 

End of year

   1,675    189.0    93.5    3,370  
  

 

 

  

 

 

  

 

 

  

 

 

 

Proved developed reserves:

     

Beginning of year

   805    103.0    39.9    1,662  

End of year

   998    124.8    47.8    2,034  

Proved undeveloped reserves:

     

Beginning of year

   428    53.4    31.0    935  

End of year

   677    64.2    45.7    1,336  

   Year Ended December 31, 2010 
   Natural Gas
(Bcf)
  Oil
(MMBbls)
  NGL
(MMBbls)
  Total
(Bcfe)
 

Proved developed and undeveloped reserves:

     

Beginning of year

   774    102.1    54.2    1,712  

Revisions of previous estimates

   22    3.9    5.2    77  

Purchase of minerals in place

   369    49.1    1.2    671  

Extensions, discoveries and other additions

   118    6.1    13.3    234  

Production

   (50  (4.8  (3.0  (97
  

 

 

  

 

 

  

 

 

  

 

 

 

End of year

   1,233    156.4    70.9    2,597  
  

 

 

  

 

 

  

 

 

  

 

 

 

Proved developed reserves:

     

Beginning of year

   549    77.9    33.9    1,220  

End of year

   805    103.0    39.9    1,662  

Proved undeveloped reserves:

     

Beginning of year

   225    24.2    20.3    492  

End of year

   428    53.4    31.0    935  

Index to Financial Statements

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)—Continued

   Year Ended December 31, 2009 
   Natural Gas
(Bcf)
  Oil
(MMBbls)
  NGL
(MMBbls)
  Total
(Bcfe)
 

Proved developed and undeveloped reserves:

     

Beginning of year

   851    84.1    50.7    1,660  

Revisions of previous estimates

   (69  10.9    4.0    20  

Purchase of minerals in place

   7    8.8    0.4    62  

Extensions, discoveries and other additions

   31    1.6    1.5    50  

Production

   (46  (3.3  (2.4  (80
  

 

 

  

 

 

  

 

 

  

 

 

 

End of year

   774    102.1    54.2    1,712  
  

 

 

  

 

 

  

 

 

  

 

 

 

Proved developed reserves:

     

Beginning of year

   585    61.9    29.6    1,134  

End of year

   549    77.9    33.9    1,220  

Proved undeveloped reserves:

     

Beginning of year

   266    22.2    21.1    526  

End of year

   225    24.2    20.3    492  

The tables above include changes in estimatedultimately recovered. Estimating quantities of proved oil, natural gas and NGL reserves shownis a complex process that involves significant interpretations and assumptions and cannot be measured in Mcf equivalents at a ratean exact manner. It requires interpretations and judgment of one barrel per six Mcf.available technical data, including the evaluation of available geological, geophysical and

Proved reserves increased by approximately 773 Bcfe

Roan Resources, Inc.

Notes to approximately 3,370 Bcfe forConsolidated Financial Statements

engineering data. The accuracy of any reserve estimate is highly dependent on the year ended December 31, 2011, from 2,597 Bcfe forquality of available data, the year ended December 31, 2010. The year ended December 31, 2011, includes 121 Bcfe in negative revisionsaccuracy of previous estimates, due primarily to 153 Bcfe in negative revisionsthe assumptions on which they are based upon, economic factors, such as oil, natural gas and NGL prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to asset performance. These negative revisionsthe lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proveddeveloped non-producing reserves and proved developed reserves that are early in their production life. As a result, the Company’s reserve estimates are inherently imprecise.

The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were partially offset by 32 Bcfe in positive revisions primarily due to higher oil prices. Twelve acquisitions duringbased. In general, the year ended December 31, 2011, increased proved reserves by approximately 579 Bcfe. In addition, extensions and discoveries, primarilyvolume of production from 292 productive wells drilled during the year, contributed approximately 450 Bcfe to the increase in proved reserves.

Proved reserves increased by approximately 885 Bcfe to approximately 2,597 Bcfe for the year ended December 31, 2010, from 1,712 Bcfe for the year ended December 31, 2009. The year ended December 31, 2010, includes 77 Bcfe in positive revisions of previous estimates, due primarily to higher oil and natural gas prices, which contributed approximately 155 Bcfe. These positive revisions were partially offset by 78 Bcfe in negative revisions primarily dueproperties the Company owns declines as reserves are depleted. Except to asset performance. Eleven acquisitions during the year ended December 31, 2010, increasedextent the Company conducts successful exploration and development activities or acquires additional properties containing proved reserves, by approximately 671 Bcfe. In addition, extensions and discoveries, primarily from 138 productive wells drilled duringor both, the year, contributed approximately 234 Bcfe to the increase in proved reserves.

Proved reserves increased by approximately 52 Bcfe to approximately 1,712 Bcfe for the year ended December 31, 2009. The year ended December 31, 2009, includes 20 Bcfe in positive revisions of previous estimates, due primarily to higher asset performance, which contributed approximately 39 Bcfe, most significantly related to well reactivations and waterflood optimization work in the Mid-Continent Shallow region. These positive revisions were partially offset by 19 Bcfe in negative revisions primarily due to decreases in natural gas prices. Two acquisitions during the year ended December 31, 2009, increasedCompany’s proved reserves by approximately 62 Bcfe. In addition, extensions and discoveries, primarily from 72 productive wells drilled during the year, contributed approximately 50 Bcfe to the increase in proved reserves.will decline as reserves are produced.

Index to Financial Statements

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)—Continued

Standardized Measure of Discounted Future Net Cash Flows

The following summary sets forth the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and Changes Therein RelatingNGL reserves.

   December 31, 
   2018   2017   2016 
   (in thousands) 

Future cash inflows

  $7,325,386   $5,270,465   $271,428 

Future production costs

   (1,773,779   (1,664,724   (102,817

Future development costs

   (1,294,565   (745,769   —   

Future income tax expense (1)

   (797,247   —      —   
  

 

 

   

 

 

   

 

 

 

Future net cash flows

   3,459,795    2,859,972    168,611 

Discount to present value at 10% annual rate

   (1,760,094   (1,664,303   (50,339
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

  $1,699,701   $1,195,669   $118,272 
  

 

 

   

 

 

   

 

 

 

(1)

Roan Inc. is a corporation, and as a result, is subject to U.S. federal, state and local income taxes. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus was not subject to U.S. federal or state income taxes.

Roan Resources, Inc.

Notes to Proved ReservesConsolidated Financial Statements

Information with respect to

Principal changes in the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relatingattributable to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to state income taxes in Texas and Michigan; however, these amounts are not material (see Note 14).as follows:

 

   December 31, 
   2011  2010  2009 
   (in thousands) 

Future estimated revenues

  $29,319,369   $20,160,275   $10,093,876  

Future estimated production costs

   (9,464,319  (6,825,147  (4,200,091

Future estimated development costs

   (2,848,497  (1,733,929  (816,577
  

 

 

  

 

 

  

 

 

 

Future net cash flows

   17,006,553    11,601,199    5,077,208  

10% annual discount for estimated timing of cash flows

   (10,391,693  (7,377,667  (3,353,926
  

 

 

  

 

 

  

 

 

 

Standardized measure of discounted future net cash flows

  $6,614,860   $4,223,532   $1,723,282  
  

 

 

  

 

 

  

 

 

 

Representative NYMEX prices:(1)

    

Natural gas (MMBtu)

  $4.12   $4.38   $3.87  

Oil (Bbl)

  $95.84   $79.29   $61.05  
   Years Ended December 31, 
   2018   2017   2016 
   (in thousands) 

Standardized measure of discounted future net cash flows at the beginning of the period

  $1,195,669   $118,272   $18,910 

Sales of oil and natural gas, net of production costs

   (374,588   (124,526   (42,868

Acquisition of reserves

   —      279,026    462 

Extensions and discoveries, net of future development costs

   1,126,713    877,846    104,581 

Previously estimated development costs incurred during the period

   124,822    148,505    —   

Net changes in prices and production costs

   172,928    36,233    18,256 

Changes in estimated future development costs

   (13,160   (17,970   —   

Revisions of previous quantity estimates

   (281,054   (5,676   15,573 

Accretion of discount

   119,567    11,827    1,891 

Net change in income taxes(1)

   (391,808   —      —   

Net changes in timing of production and other

   20,612    (127,868   1,467 
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows at the end of the period

  $1,699,701   $1,195,669   $118,272 
  

 

 

   

 

 

   

 

 

 

 

(1)In accordance with SEC regulations, reserves at December 31, 2011, December 31, 2010,

Roan Inc. is a corporation, and December 31, 2009, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month pricea result, is subject to U.S. federal, state and local income taxes. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The price usedincome tax purposes and thus was not subject to estimate reserves is held constant over the life of the reserves.U.S. federal or state income taxes.

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

   Year Ended December 31, 
   2011  2010  2009 
   (in thousands) 

Sales and transfers of oil, natural gas and NGL produced during the period

  $(822,602 $(466,964 $(228,683

Changes in estimated future development costs

   27,236    (56,001  54,141  

Net change in sales and transfer prices and production costs related to future production

   784,308    886,438    254,036  

Purchase of minerals in place

   1,452,169    1,277,134    128,779  

Extensions, discoveries, and improved recovery

   552,704    329,642    25,888  

Previously estimated development costs incurred during the period

   306,827    42,947    52,699  

Net change due to revisions in quantity estimates

   (292,343  164,999    23,672  

Accretion of discount

   422,353    172,328    142,437  

Changes in production rates and other

   (39,324  149,727    (154,054
  

 

 

  

 

 

  

 

 

 

Change—continuing operations

  $2,391,328   $2,500,250   $298,915  
  

 

 

  

 

 

  

 

 

 

Index to Financial Statements

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)—Continued

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Index to Financial Statements

LINN ENERGY, LLC

SUPPLEMENTAL QUARTERLY DATA (Unaudited)

The following discussion and analysis should be read in conjunction with LINN’s historical unaudited financial statements.

Note 17. Quarterly Financial Data (Unaudited)

The Company’s unaudited quarterly financial data for 2018 and 2017 is summarized below.

 

   Quarters Ended 
   March 31  June 30   September 30   December 31 
   (in thousands, except per unit amounts) 

2011:

       

Oil, natural gas and natural gas liquid sales

  $240,707   $302,390    $292,482    $326,458  

Gains (losses) on oil and natural gas derivatives

  $(369,476 $205,515    $824,240    $(210,339

Total revenues and other

  $(126,473 $510,571    $1,119,483    $118,873  

Total expenses(1)

  $165,625   $195,672    $211,254    $240,353  

Losses on sale of assets and other, net

  $614   $977    $279    $1,646  

Net income (loss)

  $(446,682 $237,109    $837,627    $(189,615

Net income (loss) per unit:

       

Basic

  $(2.75 $1.34    $4.74    $(1.09
  

 

 

  

 

 

   

 

 

   

 

 

 

Diluted

  $(2.75 $1.33    $4.72    $(1.09
  

 

 

  

 

 

   

 

 

   

 

 

 
   2018 
   First
Quarter
   Second
Quarter
   Third
Quarter
   Fourth
Quarter
 
   (in thousands, except per share amounts) 

Total revenues

  $91,356   $35,965   $83,448   $307,052 

Income (loss) from operations

  $36,880   $(21,670  $514   $208,819 

Net income (loss)

  $35,081   $(22,757  $(301,240  $148,245 

Earnings (loss) per share

        

Basic

  $0.23   $(0.15  $(1.97  $0.97 

Diluted

  $0.23   $(0.15  $(1.97  $0.97 

Weighted average number of shares outstanding (1)

   151,294    152,540    152,540    152,540 

 

(1)Includes

For first and second quarter of 2018, amounts reflect the following expenses: lease operating, transportation, marketing, general and administrative, exploration, bad debt, depreciation, depletion and amortization and taxes, other than income taxes.weighted average number of shares of common stock outstanding based on retrospectively reflecting the impacting of the Reorganization.

Total revenues for the 2018 quarters reflect the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to

   Quarters Ended 
   March 31  June 30  September 30   December 31 
   (in thousands, except per unit amounts) 

2010:

      

Oil, natural gas and natural gas liquid sales

  $149,386   $153,195   $177,306    $210,167  

Gains (losses) on oil and natural gas derivatives

  $96,003   $123,791   $43,505    $(188,088

Total revenues and other

  $247,036   $278,404   $222,361    $24,479  

Total expenses(1)

  $124,740   $135,980   $145,978    $200,508  

(Gains) losses on sale of assets and other, net

  $(322 $(52 $6,073    $837  

Net income (loss)

  $65,310   $59,786   $4,143    $(243,527

Net income (loss) per unit:

      

Basic

  $0.50   $0.41   $0.03    $(1.64
  

 

 

  

 

 

  

 

 

   

 

 

 

Diluted

  $0.50   $0.40   $0.03    $(1.64
  

 

 

  

 

 

  

 

 

   

 

 

 

Roan Resources, Inc.

Notes to Consolidated Financial Statements

be accounted for as a deduction from revenue. The Company elected the modified retrospective method of transition. Accordingly, comparative information from the year ended December 31, 2017 has not been adjusted and continues to be reported under the previous revenue standard.

Net loss for the third quarter of 2018 includes the recognition of $299.7 million of income tax expense primarily representing the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization (seeNote 13 – Income Taxes).

   2017 
   First
Quarter
   Second
Quarter
   Third
Quarter
   Fourth
Quarter
 
   (in thousands, except per share amounts) 

Total revenues

  $30,979   $30,290   $39,751   $58,568 

Income (loss) from operations

  $16,437   $1,867   $10,974   $(9,373

Net income (loss)

  $16,310   $1,817   $10,710   $(10,380

Earnings (loss) per share

        

Basic

  $0.22   $0.02   $0.11   $(0.07

Diluted

  $0.22   $0.02   $0.11   $(0.07

Weighted average number of shares outstanding(1)

   75,303    75,303    99,859    150,607 

 

(1)Includes

For 2017, amounts reflect the following expenses: lease operating, transportation, marketing, general and administrative, exploration, bad debt, depreciation, depletion and amortization, impairmentweighted average number of long-lived assets and taxes, other than income taxes.shares of common stock outstanding based on retrospectively reflecting the impacting of the Reorganization.

Income (loss) from operations and net income (loss) for the 2017 quarters includes bonuses paid by Citizen of approximately $9.0 million in the second quarter, impairment of unproved properties of $4.2 million in the third quarter and amortization of unproved leasehold properties of $19.6 million in the fourth quarter. Additionally, the Linn Acquisition was completed in August 2017 and the results of the properties acquired are included in the third and fourth quarters of 2017.

Index to Financial Statements

Roan Resources, Inc.

LINN ENERGY, LLCCondensed Consolidated Balance Sheets (Unaudited)

CONDENSED CONSOLIDATED BALANCE SHEETS

 

   March 31,
2012
  December 31,
2011
 
   (Unaudited)    
   

(in thousands,

except unit amounts)

 

ASSETS

  

Current assets:

   

Cash and cash equivalents

  $24,184   $1,114  

Accounts receivable—trade, net

   290,528    284,565  

Derivative instruments

   343,764    255,063  

Other current assets

   83,799    80,734  
  

 

 

  

 

 

 

Total current assets

   742,275    621,476  
  

 

 

  

 

 

 

Noncurrent assets:

   

Oil and natural gas properties (successful efforts method)

   9,128,856    7,835,650  

Less accumulated depletion and amortization

   (1,145,113  (1,033,617
  

 

 

  

 

 

 
   7,983,743    6,802,033  

Other property and equipment

   413,308    197,235  

Less accumulated depreciation

   (52,228  (48,024
  

 

 

  

 

 

 
   361,080    149,211  

Derivative instruments

   357,836    321,840  

Other noncurrent assets

   132,158    105,577  
  

 

 

  

 

 

 
   489,994    427,417  
  

 

 

  

 

 

 

Total noncurrent assets

   8,834,817    7,378,661  
  

 

 

  

 

 

 

Total assets

  $9,577,092   $8,000,137  
  

 

 

  

 

 

 

LIABILITIES AND UNITHOLDERS’ CAPITAL

   

Current liabilities:

   

Accounts payable and accrued expenses

  $403,756   $403,450  

Derivative instruments

   16,991    14,060  

Other accrued liabilities

   95,704    75,898  
  

 

 

  

 

 

 

Total current liabilities

   516,451    493,408  
  

 

 

  

 

 

 

Noncurrent liabilities:

   

Credit facility

   75,000    940,000  

Senior notes, net

   4,854,542    3,053,657  

Derivative instruments

   4,214    3,503  

Other noncurrent liabilities

   99,467    80,659  
  

 

 

  

 

 

 

Total noncurrent liabilities

   5,033,223    4,077,819  
  

 

 

  

 

 

 

Commitments and contingencies (Note 10)

   

Unitholders’ capital:

   

199,330,596 units and 177,364,558 units issued and outstanding at March 31, 2012, and December 31, 2011, respectively

   3,356,064    2,751,354  

Accumulated income

   671,354    677,556  
  

 

 

  

 

 

 
   4,027,418    3,428,910  
  

 

 

  

 

 

 

Total liabilities and unitholders’ capital

  $9,577,092   $8,000,137  
  

 

 

  

 

 

 
   March 31, 2019  December 31, 2018 
   (in thousands, except par
value and share data)
 

ASSETS

   

Current assets

   

Cash and cash equivalents

  $2,189  $6,883 

Accounts receivable

   

Oil, natural gas and natural gas liquid sales

   52,506   55,564 

Affiliates

   5,175   9,669 

Joint interest owners and other, net

   148,051   133,387 

Prepaid drilling advances

   23,132   28,977 

Derivative contracts

   14,104   82,180 

Other current assets

   10,179   6,655 
  

 

 

  

 

 

 

Total current assets

   255,336   323,315 

Noncurrent assets

   

Oil and natural gas properties, successful efforts method

   2,801,145   2,628,333 

Accumulated depreciation, depletion, amortization and impairment

   (282,541  (230,836
  

 

 

  

 

 

 

Oil and natural gas properties, net

   2,518,604   2,397,497 

Derivative contracts

   4,529   20,638 

Other

   12,967   7,659 
  

 

 

  

 

 

 

Total assets

  $2,791,436  $2,749,109 
  

 

 

  

 

 

 

LIABILITIES AND EQUITY

   

Current liabilities

   

Accounts payable

  $121,110  $49,746 

Accrued liabilities

   131,403   176,494 

Accounts payable and accrued liabilities – Affiliates

   —     8,577 

Revenue payable

   95,104   97,963 

Drilling advances

   36,149   31,058 

Derivative contracts

   5,583   845 

Other current liabilities

   2,552   790 
  

 

 

  

 

 

 

Total current liabilities

   391,901   365,473 

Noncurrent liabilities

   

Long-term debt

   602,639   514,639 

Deferred tax liabilities, net

   333,966   356,862 

Asset retirement obligations

   16,967   16,058 

Derivative contracts

   241   141 

Other

   5,679   902 
  

 

 

  

 

 

 

Total liabilities

   1,351,393   1,254,075 

Commitments and contingencies (Note 14)

   

Equity

   

Class A common stock, $0.001 par value; 800,000,000 shares authorized; 152,539,532 shares issued and outstanding at March 31, 2019 and December 31, 2018

   153   153 

Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at March 31, 2019 or December 31, 2018

   —     —   

Additionalpaid-in capital

   1,649,466   1,646,401 

Accumulated deficit

   (209,576  (151,520
  

 

 

  

 

 

 

Total equity

   1,440,043   1,495,034 
  

 

 

  

 

 

 

Total liabilities and equity

  $2,791,436  $2,749,109 
  

 

 

  

 

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Index to Financial Statements

Roan Resources, Inc.

LINN ENERGY, LLCCondensed Consolidated Statements of Operations (Unaudited)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

   Three Months Ended
March 31,
 
       2012          2011     
   (in thousands, except per unit
amounts)
 

Revenues and other:

   

Oil, natural gas and natural gas liquids sales

  $348,895   $240,707  

Gains (losses) on oil and natural gas derivatives

   2,031    (369,476

Marketing revenues

   1,290    1,173  

Other revenues

   1,874    1,123  
  

 

 

  

 

 

 
   354,090    (126,473
  

 

 

  

 

 

 

Expenses:

   

Lease operating expenses

   71,636    45,901  

Transportation expenses

   10,562    5,855  

Marketing expenses

   692    809  

General and administrative expenses

   43,321    30,560  

Exploration costs

   410    445  

Bad debt expenses

   16    (38

Depreciation, depletion and amortization

   117,276    66,366  

Taxes, other than income taxes

   25,195    15,727  

Losses on sale of assets and other, net

   1,478    614  
  

 

 

  

 

 

 
   270,586    166,239  
  

 

 

  

 

 

 

Other income and (expenses):

   

Loss on extinguishment of debt

   —      (84,562

Interest expense, net of amounts capitalized

   (77,519  (63,464

Other, net

   (3,269  (1,746
  

 

 

  

 

 

 
   (80,788  (149,772
  

 

 

  

 

 

 

Income (loss) before income taxes

   2,716    (442,484

Income tax expense

   (8,918  (4,198
  

 

 

  

 

 

 

Net loss

  $(6,202 $(446,682
  

 

 

  

 

 

 

Net loss per unit:

   

Basic

  $(0.04 $(2.75
  

 

 

  

 

 

 

Diluted

  $(0.04 $(2.75
  

 

 

  

 

 

 

Weighted average units outstanding:

   

Basic

   193,256    163,107  
  

 

 

  

 

 

 

Diluted

   193,256    163,107  
  

 

 

  

 

 

 

Distributions declared per unit

  $0.69   $0.66  
  

 

 

  

 

 

 
   Three Months Ended
March 31,
 
   2019  2018 
   (in thousands, except per
share amounts)
 

Revenues

   

Oil sales

  $60,571  $63,692 

Natural gas sales

   11,189   10,332 

Natural gas sales – Affiliates

   10,592   6,558 

Natural gas liquid sales

   8,338   11,939 

Natural gas liquid sales – Affiliates

   7,849   8,449 

Loss on derivative contracts

   (83,642  (9,614
  

 

 

  

 

 

 

Total revenues

   14,897   91,356 

Operating Expenses

   

Production expenses

   14,846   8,355 

Production taxes

   5,039   2,386 

Exploration expenses

   12,488   7,850 

Depreciation, depletion, amortization and accretion

   41,572   21,865 

General and administrative

   15,825   14,020 

Gain on sale of other assets

   (664  —   
  

 

 

  

 

 

 

Total operating expenses

   89,106   54,476 

Total operating (loss) income

   (74,209  36,880 

Other income (expense)

   

Interest expense, net

   (6,744  (1,799
  

 

 

  

 

 

 

Net (loss) income before income taxes

   (80,953  35,081 

Income tax benefit

   (22,897  —   
  

 

 

  

 

 

 

Net (loss) income

  $(58,056 $35,081 
  

 

 

  

 

 

 

Earnings (loss) per share

   

Basic

  $(0.38 $0.23 
  

 

 

  

 

 

 

Diluted

  $(0.38 $0.23 
  

 

 

  

 

 

 

Weighted average number of shares outstanding

   

Basic

   152,540   151,294 
  

 

 

  

 

 

 

Diluted

   152,540   151,294 
  

 

 

  

 

 

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Index to Financial Statements

Roan Resources, Inc.

LINN ENERGY, LLCCondensed Consolidated Statements of Changes in Equity (Unaudited)

CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL

(Unaudited)

 

   Units   Unitholders’
Capital
  Accumulated
Income
  Total
Unitholders’
Capital
 
   (in thousands) 

December 31, 2011

   177,365    $2,751,354   $677,556   $3,428,910  

Sale of units, net of underwriting discounts and expenses of $29,819

   21,090     731,542    —      731,542  

Issuance of units

   876     —      —      —    

Distributions to unitholders

     (137,590  —      (137,590

Unit-based compensation expenses

     8,171    —      8,171  

Excess tax benefit from unit-based compensation

     2,587    —      2,587  

Net loss

     —      (6,202  (6,202
  

 

 

   

 

 

  

 

 

  

 

 

 

March 31, 2012

   199,331    $3,356,064   $671,354   $4,027,418  
  

 

 

   

 

 

  

 

 

  

 

 

 
   Stockholders’ Equity        
   Common
Stock
(Shares)
   Common
Stock
   Additional
Paid-in
Capital
   Accumulated
Deficit
  Members’
Equity
   Total Equity 
   (in thousands) 

Balance at December 31, 2017

   —     $—     $—     $—    $1,584,769   $1,584,769 

Acquisition of oil and natural gas properties in exchange for equity units

   —      —      —      —     39,906    39,906 

Equity-based compensation

   —      —      —      —     2,292    2,292 

Net income

   —      —      —      —     35,081    35,081 
  

 

 

   

 

 

   

 

 

   

 

 

  

 

 

   

 

 

 

Balance at March 31, 2018

   —     $—     $—     $—    $1,662,048   $1,662,048 
  

 

 

   

 

 

   

 

 

   

 

 

  

 

 

   

 

 

 

Balance at December 31, 2018

   152,540   $153   $1,646,401   $(151,520 $—     $1,495,034 

Equity-based compensation

   —      —      3,065    —     —      3,065 

Net loss

   —      —      —      (58,056  —      (58,056
  

 

 

   

 

 

   

 

 

   

 

 

  

 

 

   

 

 

 

Balance at March 31, 2019

   152,540   $153   $1,649,466   $(209,576 $—     $1,440,043 
  

 

 

   

 

 

   

 

 

   

 

 

  

 

 

   

 

 

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Index to Financial Statements

Roan Resources, Inc.

LINN ENERGY, LLCCondensed Consolidated Statements of Cash Flows (Unaudited)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

   Three Months Ended
March 31,
 
   2012  2011 
   (in thousands) 

Cash flow from operating activities:

   

Net loss

  $(6,202 $(446,682

Adjustments to reconcile net loss to net cash provided by operating activities:

   

Depreciation, depletion and amortization

   117,276    66,366  

Unit-based compensation expenses

   8,171    5,638  

Loss on extinguishment of debt

   —      84,562  

Amortization and write-off of deferred financing fees and other

   7,433    5,732  

(Gains) losses on sale of assets and other, net

   (692  10  

Deferred income tax

   6,253    100  

Mark-to-market on derivatives:

   

Total (gains) losses

   (2,031  369,476  

Cash settlements

   58,517    65,450  

Premiums paid for derivatives

   (177,541  —    

Changes in assets and liabilities:

   

(Increase) decrease in accounts receivable – trade, net

   15,606    (36,230

Increase in other assets

   (4,336  (560

Increase (decrease) in accounts payable and accrued expenses

   (5,237  9,355  

Increase (decrease) in other liabilities

   18,296    (15,251
  

 

 

  

 

 

 

Net cash provided by operating activities

   35,513    107,966  
  

 

 

  

 

 

 

Cash flow from investing activities:

   

Acquisition of oil and natural gas properties

   (1,230,304  (257,349

Development of oil and natural gas properties

   (220,571  (93,086

Purchases of other property and equipment

   (9,895  (6,375

Proceeds from sale of properties and equipment and other

   215    (1,258
  

 

 

  

 

 

 

Net cash used in investing activities

   (1,460,555  (358,068
  

 

 

  

 

 

 

Cash flow from financing activities:

   

Proceeds from sale of units

   761,362    648,971  

Proceeds from borrowings

   2,634,802    160,000  

Repayments of debt

   (1,700,000  (408,397

Distributions to unitholders

   (137,590  (105,673

Financing fees, offering expenses and other, net

   (113,049  (89,394

Excess tax benefit from unit-based compensation

   2,587    3,918  
  

 

 

  

 

 

 

Net cash provided by financing activities

   1,448,112    209,425  
  

 

 

  

 

 

 

Net increase (decrease) in cash and cash equivalents

   23,070    (40,677

Cash and cash equivalents:

   

Beginning

   1,114    236,001  
  

 

 

  

 

 

 

Ending

  $24,184   $195,324  
  

 

 

  

 

 

 
   Three Months Ended
March 31,
 
   2019  2018 
   (in thousands) 

Cash flows from operating activities

   

Net (loss) income

  $(58,056 $35,081 

Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:

   

Depreciation, depletion, amortization and accretion

   41,572   21,865 

Unproved leasehold amortization and impairment

   11,331   7,350 

Gain on sale of other assets

   (664  —   

Amortization of deferred financing costs

   537   145 

Loss on derivative contracts

   83,642   9,614 

Net cash received (paid) upon settlement of derivative contracts

   2,549   (4,138

Equity-based compensation

   3,065   2,292 

Deferred income taxes

   (22,897  —   

Other

   1,514   —   

Changes in operating assets and liabilities increasing (decreasing) cash:

   

Accounts receivable and other assets

   (14,770  (56,369

Accounts payable and other liabilities

   15,792   (24,614
  

 

 

  

 

 

 

Net cash provided by (used in) operating activities

   63,615   (8,774

Cash flows from investing activities

   

Acquisition of oil and natural gas properties

   —     (22,935

Capital expenditures for oil and natural gas properties

   (159,381  (87,549

Acquisition of other property and equipment

   (83  (770

Proceeds from sale of other assets

   1,264   —   
  

 

 

  

 

 

 

Net cash used in investing activities

   (158,200  (111,254

Cash flows from financing activities

   

Proceeds from borrowings

   88,000   121,300 

Other

   1,891   —   
  

 

 

  

 

 

 

Net cash provided by financing activities

   89,891   121,300 
  

 

 

  

 

 

 

Net (decrease) increase in cash and cash equivalents

   (4,694  1,272 

Cash and cash equivalents, beginning of period

   6,883   1,471 
  

 

 

  

 

 

 

Cash and cash equivalents, end of period

  $2,189  $2,743 
  

 

 

  

 

 

 

Supplemental disclosure of cash flow information

   

Cash paid for interest, net of capitalized interest

  $5,718  $1,569 
  

 

 

  

 

 

 

Supplemental disclosure ofnon-cash investing and financing activities

   

Change in accrued capital expenditures

  $4,489  $(2,951

Acquisition of oil and natural gas properties for equity

  $—    $39,906 

Right of use assets obtained in exchange for operating lease liabilities

  $7,139  $—   

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Roan Resources, Inc.

IndexNotes to Unaudited Condensed Consolidated Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSNote 1 – Business and Organization

Note 1—Basis of Presentation

Nature of Business

Linn Energy,Roan Resources, Inc. (“Roan Inc.”) was formed in September 2018 to facilitate a reorganization and to become the holding company for Roan Resources LLC (“LINN Energy” orRoan LLC”). In September 2018, a series of transactions were executed with Roan LLC’s members which resulted in Roan LLC becoming a wholly owned subsidiary of Roan Inc. These transactions are hereafter referred to as the “Company”) is an independent oil“Reorganization” and natural gas company. LINN Energy’s mission isRoan Inc. with its subsidiaries are collectively referred to acquire, develop and maximize cash flow from a growing portfolioas the “Company.” SeeNote 10 – Equityfor further discussion of long-life oil and natural gas assets.the Reorganization transaction. The Company’s properties are located in the United States (“U.S.”), primarily in the Mid-Continent, the Permian Basin, the Hugoton Basin, Michigan, Illinois, the Williston/Powder River Basin and California. Effective January 1, 2012, the Company realigned its regions as follows: Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of Texas Panhandle (including Granite Wash and Cleveland horizontal plays), the Permian Basin, the Hugoton Basin, Michigan/Illinois, the Williston/Powder River Basin and California. The realignment had no effect on the Company’s operations.

Principles of Consolidation and Reporting

The condensed consolidatedaccompanying historical financial statements at March 31, 2012, and for the three months ended March 31, 2012,2018 are the financial statements of Roan LLC, our accounting predecessor. Following the Reorganization, the historical financial statements are the results of Roan Inc.

Roan LLC was initially formed by Citizen Energy II, LLC (“Citizen”) in May 2017. On August 31, 2017, a contribution agreement (the “Contribution Agreement”) by and March 31, 2011, are unaudited, butamong Roan LLC, Citizen, Linn Energy Holdings, LLC (“LEH”) and Linn Operating, LLC (“LOI”, and together with LEH, “Linn”) was executed, pursuant to which, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within anarea-of-mutual-interest to Roan LLC (collectively the “Contribution”). In exchange for their contributions, Citizen and Linn each received a 50% equity interest in Roan LLC. In conjunction with the Contribution Agreement, Roan LLC entered into management services agreements with both Citizen and Linn (“MSAs”). SeeNote 12 – Transactions with Affiliates for additional discussion of the MSAs and transactions with Citizen and Linn.

The Company was formed to engage in the opinionacquisition, exploration, development, production, and sale of management include all adjustments (consistingoil and natural gas reserves. The Company’s oil and natural gas properties are located in Central Oklahoma. The Company’s corporate headquarters is located in Oklahoma City, Oklahoma.

Note 2 – Summary of normal recurring adjustments) necessary forSignificant Accounting Policies

For a fair presentationdescription of the results forCompany’s significant accounting policies, refer to Note 2 to the interim periods. Certain information and note disclosures normallyCompany’s 2018 audited financial statements included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations, and as such this report should be read in conjunction with LINN’s historical audited financial statements.the Annual Report on Form10-K. The results reported in these unauditedaccompanying condensed consolidated financial statements should not necessarily be taken as indicativewere prepared in conformity with accounting principles generally accepted in the United States of results that may be expected forAmerica (“GAAP”).

Certain amounts in the entire year.prior period financial statements have been reclassified to conform to the 2019 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or total cash flows.

Principles of Consolidation

The condensed consolidated financial statements of the Company include the accounts of the CompanyRoan Inc. and its wholly owned subsidiaries. All significantmaterial intercompany transactionsbalances and balancestransactions have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.eliminated.

Interim Financial Statements

The condensed consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or unitholders’ capital.

Use of Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires managementas of December 31, 2018 were derived from the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to theannual financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards

In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The ASU will be applied retrospectively and is effective for periods beginning on or after January 1, 2013. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

In May 2011, the FASB issued an ASU that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The ASU is to be applied prospectively and is effective for periods beginning after December 15, 2011. The Company adopted the ASU effective January 1, 2012. The adoption of the requirements of the ASU, which expanded disclosures, had no effect on the Company’s results of operations or financial position.

Note 2—Acquisitions and Divestitures

Acquisitions—2012

On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin in Kansas from BP America Production Company (“BP”). The results of operations of these properties have been included in the Annual Report on Form10-K. The unaudited interim condensed consolidated financial statements since the acquisition date. The Company paid approximately $1.17 billion in total consideration for these properties. The transaction was financed primarily with proceeds from the March 2012 debt offering, as described below.

During the first quarter of 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition dates. The Company, in the aggregate, paid approximately $63 million in total consideration for these properties.

These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):

Assets:

  

Current

  $7,358  

Noncurrent

   207,735  

Oil and natural gas properties

   1,042,672  
  

 

 

 

Total assets acquired

  $1,257,765  
  

 

 

 

Liabilities:

  

Current liabilities

  $9,764  

Asset retirement obligations

   18,469  
  

 

 

 

Total liabilities assumed

  $28,233  
  

 

 

 

Net assets acquired

  $1,229,532  
  

 

 

 

Current assets include receivables and inventory and noncurrent assets include other property and equipment. Current liabilities include payables, ad valorem taxes payable and environmental liabilities.

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The revenues and expenses related to certain properties acquired from BP, Plains Exploration & Production Company (“Plains”), Panther Energy Company, LLC and Red Willow Mid-Continent, LLC (collectively referred to as “Panther”), SandRidge Exploration and Production, LLC (“SandRidge”) and an affiliate of Concho Resources Inc. (“Concho”) are included in the condensed consolidated results of operations of the Company as of March 30, 2012, December 15, 2011, June 1, 2011, April 1, 2011, and March 31, 2011, respectively. The following unaudited pro forma financial information presents a summary of the Company’s condensed consolidated results of operations for the three months ended March 31, 2012,2019 and March 31, 2011, assuming2018 were prepared by the acquisitionCompany in accordance with the accounting policies stated in the audited financial statements. In the opinion of management, the Company’s unaudited condensed consolidated financial statements reflect all known adjustments necessary to fairly state the financial position of the Company and its results of operations and cash flows for such periods. All such adjustments are of a normal, recurring nature. Certain information and

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

disclosures normally included in financial statements prepared in conformity with GAAP have been consolidated or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s annual financial statements and notes thereto.

Use of Estimates

The preparation of financial statements and related footnotes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management’s estimates and assumptions is the estimate of proved oil, natural gas and NGL reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from BP had been completedthese estimates.

Recent Accounting Standards Issued

In February 2016, the FASB issued ASU2016-02,Leases (Topic 842)(“ASC 842”). This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and aright-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. The Company adopted the new standard using the simplified transition method described in ASU2018-11Leases (Topic 842): Targeted Improvements as of January 1, 2011,2019 and did not retrospectively apply the new standard to periods before adoption. Accordingly, comparative information has not been adjusted and continues to be reported under the previous leasing standard. SeeNote 3—Lease Accounting for additional information on the adoption of ASC 842.

Note 3 – Lease Accounting

The Company adopted ASC 842 on January 1, 2019 using the simplified transition method described in ASU2018-11Leases (Topic 842): Targeted Improvements. Accordingly, comparative information was not adjusted and will continue to be reported under the previous lease standard. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The Company further utilized the package of practical expedients within ASC 842 that allows an entity to not reassess the following prior to the effective date (i) whether any expired or existing contracts were or contained leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases. The Company also elected the practical expedient under ASU2018-01Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 that allows it to not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. Finally, the Company has elected the short-term lease recognition exemption for all leases that qualify and the acquisitions from Plains, Panther, SandRidgepractical expedient to not separate lease and Concho had been completednon-lease components for the majority of classes of underlying assets.

The Company enters into lease agreements to support its operations, such as office space, drilling rigs and field equipment. ASC 842 does not impact the accounting or financial presentation of the Company’s mineral leases and also does not apply to leases used in the exploration or use of oil and natural gas, including the rights to explore for those natural resources and rights to use the land in which those natural resources are contained.

To facilitate compliance with ASC 842, the Company evaluated its existing lease arrangements and enhanced its systems, processes and internal controls to identify, track and record applicable leases. The implementation and

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

adoption of this standard resulted in the Company recognizingright-of-use assets and lease liabilities for certain of its operating leases on the accompanying condensed consolidated balance sheet as of January 1, 2010, including adjustments to reflectMarch 31, 2019. The Company has no finance leases. The following table shows the values assignedimpact of the adoption of ASC 842 on the Company’s current period balance sheet as compared to the netprevious lease accounting standard, ASC Topic 840,Leases (“ASC 840”):

   As of March 31, 2019 
   Under ASC 842   Under ASC 840   Increase/(decrease) 
   (in thousands) 

Other noncurrent assets

  $6,068   $—     $6,068 

Other current liabilities

  $1,813   $—     $1,813 

Other noncurrent liabilities

  $5,326   $1,071   $4,255 

Lease Accounting Policies

The Company determines if an arrangement is a lease at the inception of the arrangement by (i) identifying any assets acquired.within the contract (ii) determining whether the Company has the right to obtain substantially all of the economic benefits from use of the asset throughout the period of use and (iii) if the Company has the right to direct how and for what purpose the identified asset is used throughout the period of use. To the extent that it is determined that an arrangement represents a lease, the lease is classified as an operating lease or a finance lease. The pro forma financialCompany capitalizes both lease classifications on its consolidated balance sheets through aright-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease.

Operating leases are included in other noncurrent assets, other current liabilities, and other noncurrent liabilities in the consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Certain of the Company’s lease agreements include lease andnon-lease components. For all asset classes with multiple component types, the Company has utilized the practical expedient that exempts it from separating lease components fromnon-lease components. Accordingly, the Company accounts for the lease andnon-lease components in an arrangement as a single lease component.

In addition, for all asset classes, the Company has made an accounting policy election not to apply the lease recognition requirements to its short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that the Company is reasonably certain to exercise). Accordingly, the Company recognizes lease payments related to its short-term leases in profit or loss on a straight-line basis over the lease term. To the extent that there are variable lease payments, the Company recognizes those payments in profit or loss in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases” below for further information regarding those asset classes that include material short-term leases.

Nature of Leases

The Company leases certain office space, drilling rigs and field equipment under cancelable andnon-cancelable leases to support our operations.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Office Buildings.The Company leases its corporate office space in Oklahoma City, Oklahoma and additional office space for its field location in Oklahoma. In general, the Company’s office lease agreements contain provisions to extend the lease and contain protective provisions that allow for early termination. Beginning in March 2019, the Company began paying its portion of the building’s operating expenses, as defined in the corporate office lease agreement. These expenses are considered variable leases payments, which were not included in the measurement of the lease liability. The Company’s office building leases are long term leases reflected under ASC 842 on the accompanying condensed consolidated balance sheet as of March 31, 2019.

Drilling Rigs.The Company enters into daywork contracts for drilling rigs with third party service contractors to support the development and exploitation of undeveloped reserves. All of the Company’s current drilling contracts have a term of one year or less.

Field Equipment.The Company rents various field equipment, including compressors, from third parties in order to facilitate its operations. Compressor arrangements are typically structured with anon-cancelable primary term of twelve months and continue thereafter on amonth-to-month basis subject to termination by either party with thirty days’ notice. The Company has concluded that its compressor rental agreements represent operating leases with a lease term that equals the primarynon-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. Other field equipment arrangements are typically structured on amonth-to-month basis subject to termination by either party.

To the extent that field equipment rental arrangements have a primary term of twelve months or less, the Company has elected to apply the practical expedient for short-term leases. For those short-term arrangements, the Company does not apply the lease recognition requirements, and recognizes lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to the “Lease Accounting Policies” section above for discussion of practical expedients applied.

Discount Rate.The Company’s leases typically do not provide an implicit rate, and thus, it is required that the Company use its incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. The Company’s incremental borrowing rate reflects the rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. The Company uses the implicit rate in the limited circumstances in which that rate is readily determinable.

Note 4 – Revenue from Contracts with Customers

Revenues from the sale of oil, natural gas and NGLs are recognized when control of the product has been transferred to the customer, all performance obligations have been satisfied and collectability is reasonably assured. We recognize revenues from the sale of oil, natural gas and NGLs based on our share of volumes sold.

Performance Obligations

The Company satisfies the performance obligations under its oil and natural gas sales contracts through delivery of its production and transfer of control to a customer. Upon delivery of production, the Company has the right to receive consideration from its customers in amounts that correspond with the value of the production transferred. The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery for operated properties and within 90 days of the month of delivery fornon-operated properties.

The Company’s oil sales contracts are short-term in nature with a contract term of one year or less. For those contracts, the Company utilized the practical expedient inRevenue from Contracts with Customers (Topic 606)

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

(“ASC 606”), which provides an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s natural gas and NGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606 which states the Company is not necessarily indicativerequired to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the resultstransaction price allocated to remaining performance obligations is not required.

Contract Balances

The Company recognizes sales of operations ifoil, natural gas, and NGLs at a point in time when it satisfies a performance obligation and at that point the acquisitionsCompany has an unconditional right to receive payment. Accordingly, these contracts do not give rise to contract assets or contract liabilities under ASC 606. The Company had been effectiveaccounts receivable related to revenue from contracts with customers as of these dates.March 31, 2019 and December 31, 2018 of approximately $57.7 million and $65.2 million, respectively, which represent this unconditional right to receive payment.

Prior Period Performance Obligations

To record revenues for oil, natural gas and NGLs, the Company estimates the amount of production delivered at the end of each month and the prices expected to be received for those sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer. For the three months ended March 31, 2019 and 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Note 5 – Oil and Natural Gas Properties

The Company’s oil and natural gas properties are in the continental United States. The oil and natural gas properties include the following:

 

   Three Months Ended
March 31,
 
   2012  2011 
   

(in thousands, except

per unit amounts)

 

Total revenues and other

  $410,972   $(7,608

Total operating expenses

  $318,546   $246,692  

Net loss

  $(16,667 $(435,800

Net loss per unit:

   

Basic

  $(0.09 $(2.57
  

 

 

  

 

 

 

Diluted

  $(0.09 $(2.57
  

 

 

  

 

 

 
   March 31, 2019   December 31, 2018 
   (in thousands) 

Oil and natural gas properties

    

Proved

  $1,730,526   $1,538,379 

Unproved

   1,070,619    1,089,954 

Less: accumulated depreciation, depletion, amortization and impairment

   (282,541   (230,836
  

 

 

   

 

 

 

Oil and natural gas properties, net

  $2,518,604   $2,397,497 
  

 

 

   

 

 

 

IndexFor the three months ended March 31, 2019 and 2018, the Company recorded amortization expense on its unproved oil and natural gas properties of $11.3 million and $7.4 million, respectively, which is reflected in exploration expense on the accompanying condensed consolidated statements of operations. Unproved leasehold amortization reflects consideration of the Company’s drilling plans and the lease terms of its existing unproved properties. No impairment of proved oil and natural gas properties was recorded for the three months ended March 31, 2019 or 2018.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

 

Acquisition—Subsequent EventNote 6 – Asset Retirement Obligations

On April 3, 2012,The following is a reconciliation of the changes in the Company’s asset retirement obligation (“ARO”) for the three months ended March 31, 2019 (in thousands):

Asset retirement obligation, December 31, 2018

  $16,848 

Liabilities incurred or acquired

   667 

Revisions in estimated cash flows

   —   

Liabilities settled

   (87

Accretion expense

   278 
  

 

 

 

Asset retirement obligation, March 31, 2019

   17,706 

Less: current portion of obligations(1)

   739 
  

 

 

 

Asset retirement obligation – long term

  $16,967 
  

 

 

 

(1)

The current portion of the ARO liability is included in other current liabilities on the condensed consolidated balance sheet.

Note 7 – Long-Term Debt

In September 2017, the Company entered into a joint-venture$750.0 million credit agreement with an affiliateinitial borrowing base of Anadarko Petroleum Corporation$200.0 million and maturity on September 5, 2022 (as amended, the “Credit Facility”). Redetermination of the borrowing base of the Credit Facility occurs semiannually on or about October 1 and April 1. The redeterminations in September 2018 and March 2019 resulted in an increase to the borrowing base to $675.0 million and $750.0 million, respectively. As of March 31, 2019, the Company had $602.6 million of outstanding borrowings and no letters of credit outstanding under the Credit Facility. The Credit Facility is secured by substantially all of the assets of the Company.

The Company amended the Credit Facility in March 2019 to increase the borrowing base as noted above as well as to allow for (i) secured permitted additional debt of up to $250 million before any reduction in the borrowing base would occur and (ii) unsecured permitted additional debt of up to $400 million before any reduction in the borrowing base would occur.

Amounts borrowed under the Credit Facility bear interest at London Interbank Offered Rate (“Anadarko”LIBOR”) whereby LINN Energy will participateor the alternate base rate (“ABR”) at the Company’s election. The rate used for ABR loans is based on the higher of the prime rate, the federal funds effective rate plus 0.50% or theone-month LIBOR rate plus 1%. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the Credit Facility. Additionally, the Credit Facility provides for a commitment fee, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement):

Utilization Level

  

Utilization

  

LIBOR Margin

  

ABR Margin

  

Commitment Fee

Level I

  <25%  2.00%  1.00%  0.375%

Level II

  >25% but <50%  2.25%  1.25%  0.375%

Level III

  >50% but <75%  2.50%  1.50%  0.500%

Level IV

  >75% but <90%  2.75%  1.75%  0.500%

Level V

  >90%  3.00%  2.00%  0.500%

The Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants;

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

(ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report.

The Credit Facility also contains financial covenants requiring the Company to comply with a leverage ratio of the Company’s consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of the Company’s consolidated current assets to consolidated current liabilities (as defined in the credit agreement to excludenon-cash assets and liabilities under ASC Topic 815Derivatives and Hedging and ASC Topic 410Asset Retirement and Environmental Obligations) as of the fiscal quarter ended of not less than 1.00 to 1.00.

As of March 31, 2019, the Company was in compliance with the covenants under the Credit Facility.

Note 8 – Derivative Instruments

The Company utilizes fixed price swaps and basis swaps to manage the price risk associated with the sale of its oil, natural gas and NGL production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential, the Panhandle Eastern Pipeline or Natural Gas Pipeline Company of America Mid Continent. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume.

The following table reflects the Company’s open commodity contracts at March 31, 2019:

   2019   2020   Total 

Oil fixed price swaps

      

Volume (Bbl)

   3,874,890    3,063,500    6,938,390 

Weighted-average price

  $60.05   $60.74   $60.36 

Natural gas fixed price swaps

      

Volume (MMBtu)

   30,442,000    16,005,000    46,447,000 

Weighted-average price

  $2.91   $2.64   $2.82 

Natural gas basis swaps

      

Volume (MMBtu)

   22,000,000    7,320,000    29,320,000 

Weighted-average price

  $0.60   $0.53   $0.58 

Natural gas liquids fixed price swaps

      

Volume (Bbl)

   825,000    —      825,000 

Weighted-average price

  $32.25   $—     $32.25 

The Company nets the fair value of derivative instruments by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. SeeNote 9 – Fair Value Measurementsfor further information regarding the fair value measurement of the Company’s derivatives.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

As the Company has elected to not account for commodity derivative instruments as hedging instruments, gains or losses resulting from the change in fair value along with the gains or losses resulting from settlement of derivative contracts are reflected in loss on derivative contracts included in the accompanying condensed consolidated statements of operations.

The following table presents the Company’s loss on derivative contracts and net cash received (paid) upon settlement of its derivative contracts for the three months ended March 31, 2019 and 2018:

   Three Months Ended March 31, 2019 
           2019                   2018         
   (in thousands) 

Loss on derivative contracts

  $(83,642  $(9,614

Net cash received (paid) upon settlement of derivative contracts(1)

  $5,382   $(4,138

(1)

Includes $0.4 million of cash received upon settlement of derivative contracts prior to their contractual maturity for the three months ended March 31, 2018.

During 2018 and in 2019, the Company modified certain existing derivative contracts to comply with hedging requirements under its Credit Facility. During the three months ended March 31, 2019, the Company received $2.8 million of cash upon settlement of such modified derivative contracts. The cash settlements for these derivatives are classified as cash flows from financing activities in the accompanying condensed consolidated statement of cash flows due to the other-than-insignificant financing element contained in the modified derivative contract.

Note 9 – Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:

Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.

Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the three months ended March 31, 2019 and 2018, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company’s recurring fair value measurements are performed for its commodity derivatives. Please refer toNote 8 – Derivative Instruments for additional discussion.

Commodity Derivative Instruments

Commodity derivative contracts are stated at fair value in the accompanying condensed consolidated balance sheets. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.

The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of March 31, 2019 and December 31, 2018, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):

   March 31, 2019 
   Level 1   Level 2  Level 3   Gross Fair
Value
  Netting  Carrying
Value
 

Assets

         

Current commodity derivatives

  $—     $19,834  $—     $19,834  $(5,730 $14,104 

Noncurrent commodity derivatives

   —      5,805   —      5,805   (1,276  4,529 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total assets

  $—     $25,639  $—     $25,639  $(7,006 $18,633 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Liabilities

         

Current commodity derivatives

  $—     $(11,313 $—     $(11,313 $5,730  $(5,583

Noncurrent commodity derivatives

   —      (1,517  —      (1,517  1,276   (241
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total liabilities

  $—     $(12,830 $—     $(12,830 $7,006  $(5,824
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 
   December 31, 2018 
   Level 1   Level 2  Level 3   Gross Fair
Value
  Netting  Carrying
Value
 

Assets

         

Current commodity derivatives

  $—     $85,728  $—     $85,728  $(3,548 $82,180 

Noncurrent commodity derivatives

   —      21,565   —      21,565   (927  20,638 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total assets

  $—     $107,293  $—     $107,293  $(4,475 $102,818 
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Liabilities

         

Current commodity derivatives

  $—     $(4,393 $—     $(4,393 $3,548  $(845

Noncurrent commodity derivatives

   —      (1,068  —      (1,068  927   (141
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total liabilities

  $—     $(5,461 $—     $(5,461 $4,475  $(986
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Non-Recurring Fair Value Measurements

The Company’snon-recurring fair value measurements include the determination of the grant date fair value of the Company’s performance share units. The grant date fair value of the Company’s performance share units is determined using a Monte Carlo simulation model and is classified as a partnerLevel 3 measurement. Please refer toNote 11 – Equity Compensationfor additional discussion.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Other Financial Instruments

The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying values of cash and cash equivalents, accounts payable, revenue payable, and accounts receivable approximate fair values due to the short-term maturities of these instruments and the carrying value of long-term debt approximates fair value as the applicable interest rates are variable and reflective of market rates.

Note 10 – Equity

In September 2018 and in conjunction with the CO2 enhanced oil recovery development ofReorganization, the Salt Creek field, located in the Powder River Basin of Wyoming. Anadarko assigned LINN Energy 23%Company issued 152.5 million shares of its interest inClass A common stock to the fieldmembers of Roan LLC in exchange for future funding of $400 million of Anadarko’s development costs.their equity interest in Roan LLC. The initialReorganization was accounted for as a reverse recapitalization with Roan Inc. as the accounting acquirer and therefore did not result in any change in the accounting basis for the business combination is not complete pending detailed analysesunderlying assets. Net income before taxes and equity-based compensation were allocated ratably to the members of Roan LLC and the stockholders of Roan Inc. for the period before and after the Reorganization, respectively. For comparative purposes, the issuance of the facts and circumstances that existed asshares to the members of Roan LLC at the time of the acquisition date.Reorganization was reflected on a retroactive basis with the units outstanding during each period presented.

Acquisition—Pending

On March 7, 2012,For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company entered intoAgreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued 1.5 billion membership units representing capital interests in Roan LLC (the “LLC Units”) for a definitive purchase and sale agreement50% equity interest in Roan LLC, to acquire certainLinn in exchange for the contribution of oil and natural gas properties locatedproperties. Additionally, Roan LLC issued 1.5 billion LLC Units, which represented a 50% equity interest, to Citizen in east Texasexchange for a contract pricethe contribution of $175 million. The Company anticipates the acquisition will close May 1, 2012, subject to closing conditions, and will be financed with borrowings under its Credit Facility, as defined in Note 6.

Acquisition—2011

On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Williston Basin from Concho.properties. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $194 million in cash and recorded a receivable from Concho of $2 million, resulting in total consideration for the acquisition of approximately $192 million. The transaction was financed primarily with proceeds from the Company’s March 2011 public offering of units, as described below.

Note 3—Unitholders’ Capital

Equity Distribution Agreement

In August 2011, the Company entered into an equity distribution agreement, pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any salefair value of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions andLLC Units issued to Citizen was the repayment of debt.

In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $1 million in commissions and professional service expenses). The Company used the net proceeds for general corporate purposes including the repayment of a portionsame as that of the indebtedness outstanding under its Credit Facility. At March 31, 2012, units equaling approximately $411 million in aggregate offering price remained availableLLC Units issued to be issued and sold under the agreement.

Public Offering of Units

In January 2012, the Company sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $29 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

Linn.

In March 2011,2018, Roan LLC issued 19.2 million LLC Units to each Citizen and Linn to settle amounts due for the leasehold acreage acquired on Roan LLC’s behalf during 2017.

Note 11 – Equity Compensation

The Company sold 16,726,067has adopted the Roan Resources, Inc. Amended and Restated Management Incentive Plan (the “Plan”), which provides for grants of options, stock appreciation rights, restricted stock unit, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards.

Performance Share Units

Prior to the Reorganization, Roan LLC granted performance share units representing limited liability company interests at $38.80 per unit ($37.248 per unit, netto certain of underwriting discount) for net proceedsits employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of approximately $623 million (after underwriting discountperformance share units under the Plan, hereafter referred to as the “PSUs,” and offering expensesare subject to the terms of approximately $26 million)the Plan and individual award agreements. The amount of PSUs that can be earned range from 0% to 200% based on the Company’s market value on December 31, 2020 (“Performance Period End Date”). The Company used a portionCompany’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the net proceeds fromCompany’s Class A common stock for the sale30 consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the issuance of these units to fund the March 2011 redemptions of a portionone share of the outstanding 2017 Senior Notes and 2018 Senior Notes and to fundCompany’s Class A common stock. Other than the cash tender offers and related expenses for a portionsecurity in which the PSUs are settled, no terms of the remaining 2017 Senior Notes and 2018 Senior Notes (see Note 6). The Company usedPSUs were modified in connection with the remaining net proceeds from the sale of units to finance a portionconversion of the March 31, 2011, acquisition in the Williston/Powder River Basin region.PSUs.

Distributions

Roan Resources, Inc.

UnderNotes to Unaudited Condensed Consolidated Financial Statements

The following table presents activity for the Company’s limited liability company agreement, the Company’s unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Distributions paid by the CompanyPSUs during the three months ended March 31, 2012, are presented2019:

   Number of
PSUs
   Weighted
Average Fair
Value
   Total
Fair Value
($ in thousands)
 

Outstanding at December 31, 2018

   1,158,750   $30.95   $35,864 

Granted

   —      —      —   

Vested

   —      —      —   

Forfeited

   —      —      —   
  

 

 

   

 

 

   

 

 

 

Outstanding at March 31, 2019

   1,158,750   $30.95   $35,864 
  

 

 

   

 

 

   

 

 

 

Compensation expense associated with the PSUs for the three months ended March 31, 2019 and 2018 was $3.0 million and $2.3 million, respectively, and is included in general and administrative expenses on the accompanying condensed consolidated statementstatements of unitholders’ capital. On April 24, 2012,operations. Unrecognized expense as of March 31, 2019 for all outstanding PSU awards was $21.4 million and will be recognized over a weighted-average remaining period of 1.75 years.

The grant date fair value of the PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned and estimated Company value on the Performance Period End Date. The grant date fair value of the PSUs is expensed on a straight-line basis from the grant date to the Performance Period End Date.

Restricted Stock Units

Under the Plan, the Company is authorized to issue restricted stock units, hereafter referred to as the “RSUs,” to eligible employees and other service providers. The Company estimates the fair values of RSUs as the closing price of the Company’s BoardClass A common stock on the grant date of Directors declaredthe award, which is expensed over the applicable vesting period.

The following table presents activity for the Company’s RSUs during the three months ended March 31, 2019:

   Number of
RSUs
   Weighted
Average Fair
Value
   Total
Fair Value
($ in thousands)
 

Outstanding at December 31, 2018

   11,800   $16.95   $200 

Granted

   —      —      —   

Vested

   —      —      —   

Forfeited

   —      —      —   
  

 

 

   

 

 

   

 

 

 

Outstanding at March 31, 2019

   11,800   $16.95   $200 
  

 

 

   

 

 

   

 

 

 

Compensation expense associated with the RSUs for three months ended March 31, 2019 was $0.05 million and is included in general and administrative expenses on the accompanying condensed consolidated statements of operations. There were no RSUs issued prior to the Reorganization in 2018. Unrecognized expense as of March 31, 2019 for all outstanding RSUs was $0.1 million and will be recognized over a cash distributionweighted-average remaining period of $0.725 per unit0.58 years.

Under the treasury stock method, both the PSUs and the RSUs are antidilutive for the weighted average share calculation and therefore are excluded from dilutive weighted average shares in the accompanying condensed consolidated statements of operations.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 12 –Transactions with Affiliates

Management Service Agreements

Under the MSAs, Citizen and Linn provided certain services in respect to the first quarter of 2012, which represents a 5% increase over the previous quarter. The distribution, totaling approximately $145 million, will be paid on May 15, 2012,oil and natural gas properties they contributed to unitholders of recordRoan LLC. Such services included serving as operator of the close of business on May 8, 2012.

Note 4—Oiloil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil, natural gas properties contributed, land administration, marketing, information technology and NGL production activitiesaccounting services. As a result of Citizen and Linn continuing to serve as operator of the contributed assets and contracting directly with applicable accumulated depletionvendors for goods and amortization are presented below:

   March 31,
2012
  December 31,
2011
 
   (in thousands) 

Proved properties:

   

Leasehold acquisition

  $7,060,195   $6,040,239  

Development

   1,733,729    1,484,486  

Unproved properties

   334,932    310,925  
  

 

 

  

 

 

 
   9,128,856    7,835,650  

Less accumulated depletion and amortization

   (1,145,113  (1,033,617
  

 

 

  

 

 

 
  $7,983,743   $6,802,033  
  

 

 

  

 

 

 

Note 5—Unit-Based Compensationservices for operations, Citizen and Linn collected amounts due from joint interest owners for their share of costs and billed Roan LLC for its share of costs. The services provided under the MSAs ended in April 2018 when Roan LLC took over as operator for the oil and natural gas properties contributed by Citizen and Linn. In conjunction with the conclusion of the MSAs in April 2018, Roan LLC assumed certain working capital accounts associated with the properties contributed from Citizen and Linn.

During the three months ended March 31, 2012,2018, Roan LLC incurred approximately $7.5 million for charges related to the Company granted an aggregate 913,663 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $34 million. The restricted units vest over three years. A summary of unit-based compensationservices provided under the MSAs, which were recorded in general and administrative expenses included onin the condensed consolidated statements of operations is presented below:operations. As the MSA ended in April 2018, there were no such charges related to the MSA in the three months ended March 31, 2019.

Acquisition of Acreage

   Three Months Ended
March 31,
 
   2012   2011 
   (in thousands) 

General and administrative expenses

  $7,622    $5,404  

Lease operating expenses

   549     234  
  

 

 

   

 

 

 

Total unit-based compensation expenses

  $8,171    $5,638  
  

 

 

   

 

 

 

Income tax benefit

  $3,019    $2,083  
  

 

 

   

 

 

 

IndexAs provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage totaling $63.0 million as of December 31, 2017 within an area of mutual interest on behalf of the Company. SeeNote 10 – Equityfor further discussion of the settlement of the payable due to Financial Statements

LINN ENERGY, LLCCitizen and Linn related to the additional acquired acreage.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

Note 6—DebtNatural Gas Dedication Agreement

The following summarizes debt outstanding:

   March 31, 2012  December 31, 2011 
   Carrying
Value
  Fair
Value(1)
   Interest
Rate(2)
  Carrying
Value
  Fair
Value(1)
   Interest
Rate(2)
 
   (in millions, except percentages) 

Credit facility

  $75   $75     2.00 $940   $940     2.57

11.75% senior notes due 2017

   41    46     12.73  41    46     12.73

9.875% senior notes due 2018

   14    16     10.25  14    16     10.25

6.50% senior notes due May 2019

   750    732     6.62  750    742     6.62

6.25% senior notes due November 2019

   1,800    1,739     6.25  —      —       —    

8.625% senior notes due 2020

   1,300    1,401     9.00  1,300    1,406     9.00

7.75% senior notes due 2021

   1,000    1,034     8.00  1,000    1,036     8.00

Less current maturities

   —      —        —      —      
  

 

 

  

 

 

    

 

 

  

 

 

   
   4,980   $5,043      4,045   $4,186    
   

 

 

     

 

 

   

Unamortized discount

   (50     (51   
  

 

 

     

 

 

    

Total debt, net of discount

  $4,930      $3,994     
  

 

 

     

 

 

    

(1)The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.
(2)Represents variable interest rateCompany has a gas dedication agreement with Blue Mountain Midstream LLC (“Blue Mountain”), a subsidiary of Riviera Resources, Inc. (“Riviera”), which has directors and shareholders in common with the Company. Amounts due from Blue Mountain at March 31, 2019 and December 31, 2018 are reflected as Accounts receivable – Affiliates in the accompanying condensed consolidated balance sheets and represent accrued revenue for the Credit Facility and effective interest rates for the senior notes.

Credit Facility

The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. In October 2011, as partportion of the semi-annual redetermination, a borrowing base of $3.0 billion was approved by the lenders with a maximum commitment amount of $1.5 billion. In February 2012, lenders approved an increaseproduction sold to Blue Mountain. Sales to Blue Mountain are reflected as Natural gas sales – Affiliates and Natural gas liquids sales – Affiliates in the maximum commitment amount to $2.0 billion. As a result of the Company’s March 2012 debt offering, the borrowing base was reduced from $3.0 billion to $2.6 billion, but the Company’s availability under the facility remains at the maximum commitment amount of $2.0 billion. The maturity date is April 2016.

During 2012, in connection with amendments to its Credit Facility, the Company incurred financing fees and expenses of approximately $2 million, which will be amortized over the life of the Credit Facility. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on theaccompanying condensed consolidated statements of operations. See further discussion of this gas dedication agreement inNote 14 – Commitments and Contingencies.

At March 31, 2012, available borrowing capacityCorporate Office Lease

During 2018, the Company entered into a lease for office space in Oklahoma City, Oklahoma that is owned by a subsidiary of Riviera under a lease with an initial term of 5 years with an option to extend the Credit Facility was $1.9 billion, which includes a $4 million reduction in availabilitylease for outstanding letters of credit.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as upon requested interim redeterminations, by the lenders at their sole discretion. The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

result in a decrease in the borrowing base. The Company’s obligations under the Credit Facility are secured by mortgages on its and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries. The Company and its subsidiaries are required to maintain the mortgages on properties representing at least 80% of the total value of its and its subsidiaries’ oil and natural gas properties. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and5 years at the end of the applicable interest period for loans bearing interest at LIBOR.initial term. The Company is required to pay a commitment fee topaid $0.3 million during the lendersthree months ended March 31, 2019 under this lease. Total remaining payments under the Credit Facility, which accrues at a rate per annum equal to 0.5% onlease are $7.8 million, excluding the average daily unused amountCompany’s portion of the lesser of: (i) the maximum commitment amountoperating expenses of the lenders and (ii) the then-effective borrowing base. The Company is in compliance with all financial and other covenants of the Credit Facility.building.

Senior Notes Due November 2019Tax Matters Agreement

On March 2, 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (“November 2019 Senior Notes”) at a price of 99.989%. The November 2019 Senior Notes were sold to a group of initial purchasers and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds of approximately $1.77 billion (after deducting the initial purchasers’ discount of $198,000 and offering expenses of approximately $29 million). The Company used the net proceeds to fund the BP acquisition (see Note 2). The remaining proceeds were used to repay indebtedness under its Credit Facility and for general corporate purposes. The financing fees and expenses of approximately $29 million incurred in connectionIn conjunction with the November 2019 Senior Notes will be amortized over the life of the notes. Such amortized expenses and discount are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.

The November 2019 Senior Notes were issued under an indenture dated March 2, 2012 (“November 2019 Indenture”), mature November 1, 2019, and bear interest at 6.25%. Interest is payable semi-annually on May 1 and November 1, beginning November 1, 2012. The November 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries has guaranteed the November 2019 Senior Notes on a senior unsecured basis. The November 2019 Indenture provides that the Company may redeem: (i) on or prior to November 1, 2015, up to 35% of the aggregate principal amount of the November 2019 Senior Notes at a redemption price of 106.25% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the November 2019 Indenture) and accrued and unpaid interest; and (iii) on or after November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to 103.125%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The November 2019 Indenture also provides that, if a change of control (as defined in the November 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the November 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

The November 2019 Indenture contains covenants substantially similar to those under the Company’s May 2019 Senior Notes, 2010 Issued Senior Notes and Original Senior Notes, as defined below, that, among other things, limit the Company’s ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of the November 2019 Senior Notes.

In connection with the issuance and sale of the November 2019 Senior Notes,Reorganization, the Company entered into a Registration Rights Agreementtax matters agreement (“November 2019 Registration Rights Agreement”TMA”) with Riviera. SeeNote 13 – Income Taxesfor further discussion of the initial purchasers. UnderTMA and the Novemberrelated amount paid to Riviera.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Water Management Services Agreement

In January 2019, Registration Rights Agreement, the Company agreed to use its reasonable efforts to fileentered into a water management services agreement with the SECBlue Mountain. Under this agreement, Blue Mountain will provide water management services including pipeline gathering, disposal, treatment and cause to become effective a registration statement relating toredelivery of recycled water. The agreement provides for an offer to issue new notes having terms substantially identical to the November 2019 Senior Notesacreage dedication for water management services through January 2029. Blue Mountain began providing services under this agreement in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the November 2019 Senior Notes. If the Company fails to satisfy these obligations, the Company may be required to pay additional interest to holders of the November 2019 Senior Notes under certain circumstances.April 2019.

Senior Notes Due May 2019Note 13 – Income Taxes

On May 13, 2011, the Company issued $750 millionAs discussed in aggregate principal amount of 6.50% senior notes due 2019 (the “May 2019 Senior Notes”). The indentures related to the May 2019 Senior Notes contain redemption provisionsNote 1 – Business and covenants that are substantially similar to those of the November 2019 Senior Notes.

Senior Notes Due 2020 and Senior Notes Due 2021Organization

The Company has $1.3 billion, Roan Inc. was formed in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”). The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes. However, in 2011, the Company caused the trustee to remove the restrictive legends from each of the 2010 Issued Senior Notes making them freely tradable (other than with respect to persons that are affiliates of the Company), thereby terminating the Company’s obligations under each of the registration rights agreements entered intoSeptember 2018 in connection with the issuanceReorganization. The Company’s accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the 2010 Issued Senior Notes.

Senior Notes Due 2017historical financial statements of Roan LLC since the income tax was an obligation of its members. Roan Inc. is a corporation and Senior Notes Due 2018subject to U.S. federal and state income tax.

The Company also has $41 million (originally $250 million) in aggregate principal amount of 11.75% senior notes due 2017 (the “2017 Senior Notes”) and $14 million (originally $256 million) in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Senior Notes” and together with the 2017 Senior Notes, the “Original Senior Notes”). The indentures related to the Original Senior Notes initially contained redemption provisions and covenants that were substantially similar to thoserecords its quarterly tax provision based on an estimate of the November 2019 Senior Notes; however,annual effective tax rate expected to apply to continuing operations for the various jurisdictions in conjunction with the tender offers in 2011, the indentures were amendedwhich it operates. The Company’s effective combined U.S. federal and most of the covenants and certain default provisions were eliminated. The amendments became effective upon the execution of the supplemental indentures to the indentures governing the Original Senior Notes.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

In March 2011, in accordance with the indentures related to the Original Senior Notes, the Company redeemed and also repurchased through cash tender offers, a portion of the Original Senior Notes. In connection with the redemptions and cash tender offers of a portion of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $85 millionstate income tax rate for the three months ended March 31, 2011.

Note 7—Derivatives

Commodity Derivatives

2019 was 28.3% based on estimated net income for the year. The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instrumentstax effects of certain items, such as swap contracts, put optionstax rate changes, significant unusual or infrequent items, and collars to economically hedge its forecasted oil, natural gas and NGL sales. The Company did not designate any of these contracts as cash flow hedges; therefore, thecertain changes in fair valuethe assessment of these instrumentsthe realizability of deferred taxes, are recordedrecognized as discrete items in current earnings. See Note 8 for fair value disclosures about oilthe period in which they occur and natural gas commodity derivatives.are excluded from the estimated annual effective tax rate.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

The following table summarizes open positions as of March 31, 2012, and represents, as of such date, derivatives in place through December 31, 2016, on annual production volumes:

   April 1 –
December 31,
2012
  2013  2014  2015  2016 

Natural gas positions:

      

Fixed price swaps:

      

Hedged volume (MMMBtu)

   55,416    81,815    90,904    99,937    20,240  

Average price ($/MMBtu)

  $5.40   $5.31   $5.35   $5.43   $4.06  

Puts:(1)

      

Hedged volume (MMMBtu)

   49,984    64,298    56,998    58,714    24,297  

Average price ($/MMBtu)

  $5.48   $5.49   $5.00   $5.00   $5.00  

Total:

      

Hedged volume (MMMBtu)

   105,400    146,113    147,902    158,651    44,537  

Average price ($/MMBtu)

  $5.44   $5.39   $5.21   $5.27   $4.57  

Oil positions:

      

Fixed price swaps:(2)

      

Hedged volume (MBbls)

   6,508    9,523    9,523    10,070    —    

Average price ($/Bbl)

  $97.57   $98.19   $95.67   $98.38   $—    

Puts:

      

Hedged volume (MBbls)

   1,742    2,440    513    —      —    

Average price ($/Bbl)

  $100.00   $100.00   $100.00   $—     $—    

Total:

      

Hedged volume (MBbls)

   8,250    11,963    10,036    10,070    —    

Average price ($/Bbl)

  $98.08   $98.56   $95.89   $98.38   $—    

Natural gas basis differential positions:(3)

      

Panhandle basis swaps:

      

Hedged volume (MMMBtu)

   56,191    77,800    79,388    87,162    19,764  

Hedged differential ($/MMBtu)

  $(0.56 $(0.56 $(0.33 $(0.33 $(0.31

MichCon basis swaps:

      

Hedged volume (MMMBtu)

   7,315    9,600    9,490    9,344    —    

Hedged differential ($/MMBtu)

  $0.12   $0.10   $0.08   $0.06   $—    

Houston Ship Channel basis swaps:

      

Hedged volume (MMMBtu)

   4,190    5,731    5,256    4,891    4,575  

Hedged differential ($/MMBtu)

  $(0.10 $(0.10 $(0.10 $(0.10 $(0.10

Permian basis swaps:

      

Hedged volume (MMMBtu)

   3,410    4,636    4,891    5,074    —    

Hedged differential ($/MMBtu)

  $(0.19 $(0.20 $(0.21 $(0.21 $—    

Oil timing differential positions:

      

Trade month roll swaps:(4)

      

Hedged volume (MBbls)

   4,617    6,315    6,315    840    —    

Hedged differential ($/Bbl)

  $0.21   $0.21   $0.21   $0.17   $—    

(1)Includes certain outstanding natural gas puts of approximately 7,964 MMMBtu for the period April 1, 2012, through December 31, 2012, 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associatedIn conjunction with NGL production.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

(2)Includes certain outstanding fixed price oil swaps on 14,750 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2016, December 31, 2017, and December 31, 2018, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
(3)Settle on the respective pricing index to hedge basis differential associated with natural gas production.
(4)The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the three months ended March 31, 2012,Reorganization, the Company entered into commodity derivative contracts consistingthe TMA with Riviera. The TMA, in part, provides for the indemnification of oilthe Company and natural gas swapsthe entitlement of Riviera to refunds related to certain taxes of Linn Energy, Inc. prior to the spinoff of Riviera from Linn Energy, Inc. As a result of the TMA and puts for April 2012 through December 2016, andthe refund of an overpayment of estimated federal taxes by Linn Energy, Inc. related to the Riviera business that was received by the Company in November 2018, the Company paid premiums for put options of approximately $178 million. Also$7.6 million to Riviera during the three months ended March 31, 2012, the Company entered into natural gas basis swaps for April 2012 through December 2016.2019.

Settled derivatives on natural gas productionNote 14 – Commitments and Contingencies

Lease Commitments

As discussed inNote 3 – Lease Accounting, we lease certain office buildings, drilling rigs, and field equipment under cancelable andnon-cancelable leases to support our operations.

The Company’s lease costs for the three months ended March 31, 2012,2019 included volumesoperating lease costs of 23,642 MMMBtu, at an average$0.4 million and short-term lease costs of $33.5 million. Short-term lease costs exclude leases with a contract priceterm of $5.84 per MMBtu. Settled derivatives onone month or less. Included in short-term lease costs is $32.2 million of gross costs related to the Company’s drilling rig leases. The Company’s portion of the drilling rig costs are capitalized to oil productionand natural gas properties and the remainder is billed out to third-party interest owners for their share of such costs. Payments made for operating leases included in lease liabilities for the three months ended March 31, 2012, included volumes of 2,578 MBbls at an average contract price of $97.93 per Bbl. Settled derivatives on natural gas production for the three months ended March 31, 2011, included volumes of 16,072 MMMBtu, at an average contract price of $8.25 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2011, included volumes of 1,807 MBbls at an average contract price of $84.20 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.2019 were $0.3 million.

Balance Sheet Presentation

Roan Resources, Inc.

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:

   March 31,
2012
   December 31,
2011
 
   (in thousands) 

Assets:

    

Commodity derivatives

  $1,092,739    $880,175  
  

 

 

   

 

 

 

Liabilities:

    

Commodity derivatives

  $412,344    $320,835  
  

 

 

   

 

 

 

By using derivative instrumentsNotes to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas

Index toUnaudited Condensed Consolidated Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.1 billion at March 31, 2012. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives, including realized and unrealized gains and losses, are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” Realized gains (losses), excluding canceled derivatives, represent amounts related to the settlement of derivative instruments and are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items.

The following presents the Company’s reported gains and losses on derivative instruments:

   Three Months Ended
March 31,
 
   2012  2011 
   (in thousands) 

Realized gains:

   

Commodity derivatives

  $55,255   $55,809  

Unrealized losses:

   

Commodity derivatives

   (53,224  (425,285
  

 

 

  

 

 

 

Total gains (losses):

   

Commodity derivatives

  $2,031   $(369,476
  

 

 

  

 

 

 

Note 8—Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

 

The following presents the fair value hierarchy forCompany’s condensed consolidated balance sheet as of March 31, 2019 included lease assets and liabilities measured at fair value on a recurring basis:

   March 31, 2012 
   Level 2   Netting(1)  Total 
   (in thousands) 

Assets:

     

Commodity derivatives

  $1,092,739    $(391,139 $701,600  

Liabilities:

     

Commodity derivatives

  $412,344    $(391,139 $21,205  

(1)Represents counterparty netting under agreements governing such derivatives.

Note 9—Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2% for the three months ended March 31, 2012); and (iv) a credit-adjusted risk-free interest rate (average of 7.35% for the three months ended March 31, 2012). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The following presents a reconciliation of the asset retirement obligationsfollows (in thousands):

 

Asset retirement obligations at December 31, 2011

  $ 71,142  

Liabilities added from acquisitions

   18,469  

Liabilities added from drilling

   274  

Current year accretion expense

   1,385  

Settlements

   (1,043
  

 

 

 

Asset retirement obligations at March 31, 2012

  $90,227  
  

 

 

 

Operating Leases

  

Operating lease right of use assets

  $6,068 

Current operating lease liabilities

  $1,813 

Noncurrent operating lease liabilities

   5,326 
  

 

 

 

Total operating lease liabilities

  $7,139 
  

 

 

 

Note 10—CommitmentsThe weighted average remaining lease term for our operating leases is 4.1 years and Contingenciesthe weighted average discount rate is 8.5%.

The Company’s operating lease liabilities as of March 31, 2019 with enforceable contract terms that are greater than one year mature as follows (in thousands):

2019

  $1,384 

2020

   2,046 

2021

   2,136 

2022

   2,229 

2023

   456 

Thereafter

   171 
  

 

 

 

Total lease payments

   8,422 

Less imputed interest

   (1,283
  

 

 

 

Total

  $7,139 
  

 

 

 

Litigation

The Company has been named as a defendant in a number ofis party to lawsuits including claims from royalty owners related to disputed royalty payments and royalty valuations. The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company. Discovery in this dispute is ongoing and is not complete. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any. In addition, the Company is involved in various other disputes arising in the ordinary course of business.business, including, but not limited to, commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The Company iscannot predict the outcome of any such lawsuits with certainty, but management does not currently believe that any pending or threatened legal matters will have a partymaterial adverse impact on the Company’s financial condition.

Due to anythe nature of its business, the Company is, from time to time, involved in other routine litigation or subject to disputes or claims related to its business activities, including workers’ compensation claims and employment related disputes. In the opinion of management, none of these other pending litigation disputes or claims that it believes wouldagainst the Company, if decided adversely, will have a material adverse effect on its overall business,the Company’s financial position,condition, cash flows or results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.operations.

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

In 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”) (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan (“Plan”) was approved by the Bankruptcy Court. Based on the recovery estimates described in the approved disclosure statement relating to the Plan, the Company expects to ultimately receive a substantial portion of the Company Claim. At March 31, 2012, the Company had a net receivable, which was valued based on market expectations, of approximately $7 million from Lehman Commodity Services related to canceled derivative contracts, and is included in “other current assets” on the consolidated balance sheets. An initial distribution under the Plan of approximately $25 million was received by the Company on April 19, 2012.

Note 11—Earnings Per Unit

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss:

   Net Loss
(Numerator)
  Units
(Denominator)
   Per Unit
Amount
 
   (in thousands) 

Three months ended March 31, 2012:

     

Net loss:

     

Allocated to units

  $(6,202   

Allocated to unvested restricted units

   (1,375   
  

 

 

    
  $(7,577   
  

 

 

    

Net loss per unit:

     

Basic net loss per unit

    193,256    $(0.04

Dilutive effect of unit equivalents

    —       —    
   

 

 

   

 

 

 

Diluted net loss per unit

    193,256    $(0.04
   

 

 

   

 

 

 

Three months ended March 31, 2011:

     

Net loss:

     

Allocated to units

  $(446,682   

Allocated to unvested restricted units

   (1,219   
  

 

 

    
  $(447,901   
  

 

 

    

Net loss per unit:

     

Basic net loss per unit

    163,107    $(2.75

Dilutive effect of unit equivalents

    —       —    
   

 

 

   

 

 

 

Diluted net loss per unit

    163,107    $(2.75
   

 

 

   

 

 

 

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 2 million unit options and warrants for the three months ended March 31, 2012, and March 31, 2011. All equivalent units were anti-dilutive for the three months ended March 31, 2012, and March 31, 2011.

Note 12—Income TaxesEnvironmental Matters

The Company is a limited liability company treated as a partnership forsubject to various federal, state and state income tax purposes, withlocal laws and regulations relating to the exceptionprotection of the stateenvironment. These laws, which are often changing, regulate the discharge of Texas, with income tax liabilities and/materials into the environment and may require the Company to remove or benefitsmitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company passed throughhas established procedures for the ongoing evaluation of its operations to unitholders. Limited liability companies are subjectidentify potential environmental exposures and to Texas margin tax. Limited liability companies were also subject to state income taxes in Michigan during the three months endedcomply with regulatory policies and procedures. At March 31, 2011. In addition, certain2019, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Natural Gas Dedication Agreements

The Company has dedicated its natural gas production from the Company’s subsidiaries are Subchapter C-corporations subject to federaloil and state income taxes. As such,natural gas properties contributed by Citizen under an agreement with the exception of the state of Texas and certain subsidiaries,a third party. Under this dedication agreement, the Company is required to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.

For the oil and natural gas properties contributed by Linn, the Company assumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.

Volume Commitment

Under an agreement with a third party, the Company has a requirement to deliver a minimum volume of natural gas from a specified area, as defined in the agreement. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees on any undelivered volumes as of November 2021. Based on expected production from currently producing wells in the specified area, the Company anticipates that it may not deliver the required minimum volume of natural gas by November 2021. As a taxable entity, it does not directly pay federal and state income taxes and recognitionresult, the Company has not been given to federal and state income taxesaccrued $0.4 million for the operationsits share of the Company. Amounts recognized for these taxes are reportedestimated shortfall deficiency fees as of March 31, 2019. The accrued liability is included in “income tax expense” onother noncurrent liabilities in the condensed consolidated statements of operations.

Note 13—Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

“Other accrued liabilities” reported on theaccompanying condensed consolidated balance sheets includesheet. If the following:

   March 31,
2012
   December 31,
2011
 
   (in thousands) 

Accrued compensation

  $8,762    $19,581  

Accrued interest

   84,796     55,170  

Other

   2,146     1,147  
  

 

 

   

 

 

 
  $95,704    $75,898  
  

 

 

   

 

 

 

Supplemental disclosuresCompany is unable to deliver any natural gas volumes subsequent to March 31, 2019 through November 2021, total shortfall deficiency fees of $7.5 million would be due at the condensed consolidated statements of cash flows are presented below:

   Three Months Ended
March 31,
 
   2012  2011 
   (in thousands) 

Cash payments for interest, net of amounts capitalized

  $42,517   $62,983  
  

 

 

  

 

 

 

Cash payments for income taxes

  $20   $557  
  

 

 

  

 

 

 

Noncash investing activities:

   

In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:

   

Fair value of assets acquired

  $1,257,765   $234,482  

Cash paid, net of cash acquired

   (1,230,304  (237,349

Receivables from sellers

   772    2,087  

Payables to sellers

   —      (1,456
  

 

 

  

 

 

 

Liabilities assumed

  $28,233   $(2,236
  

 

 

  

 

 

 

Index to Financial Statements

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—Continued

For purposesend of the condensed consolidated statementscommitment period.

Report of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $4 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2012, and December 31, 2011, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility. At December 31, 2011, approximately $54 million was included in “accounts payable and accrued expenses” on the consolidated balance sheet which represents reclassified net outstanding checks. There was no such balance at March 31, 2012. The Company presents these net outstanding checks as cash flows from financing activities on the condensed consolidated statements of cash flows.

Note 14—Subsidiary Guarantors

The November 2019 Senior Notes, the May 2019 Senior Notes, the 2010 Issued Notes and the Original Senior Notes are guaranteed by all of the Company’s material subsidiaries. The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

Index to Financial Statements

REPORT OF INDEPENDENT AUDITORSIndependent Auditors

To the Board of Directors and Unitholders

Linn Energy, LLCManagers of Roan Resources LLC:

We have audited the accompanying Statementfinancial statements of Revenuescertain oil and Direct Operating Expensesnatural gas properties contributed by Linn Energy, Inc. (the “LINN Properties”), which comprise the statements of the Assets acquired from BP America Production Company (“BP”)revenues and direct operating expenses for the yeareight months ended August 31, 2017 and for the years ended December 31, 2011. This2016 and 2015.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statement isstatements in accordance with accounting principles generally accepted in the responsibilityUnited States of Linn Energy, LLC management. America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on the financial statementstatements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States.States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement isstatements are free offrom material misstatement.

An audit includes examining, on a test basis,involves performing procedures to obtain audit evidence supportingabout the amounts and disclosures in the financial statement.statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes assessingevaluating the basisappropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statement.statements. We believe that ourthe audit providesevidence we have obtained is sufficient and appropriate to provide a reasonable basis for our audit opinion.

The accompanying financial statement was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1. The presentation is not intended to be a complete financial statement presentation of the properties described above.Opinion

In our opinion, the financial statementstatements referred to above presentspresent fairly, in all material respects, the revenues and direct operating expenses asof the LINN Properties for the eight months ended August 31, 2017 and the years ended December 31, 2016 and 2015 in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

The accompanying special purpose financial statements reflect the revenues and direct operating expenses of the LINN Properties using the basis of preparation described in Note 1 to the financial statements and are not intended to be a complete presentation of the assets acquired from BP forfinancial position, results of operations or cash flows of the year ended December 31, 2011, in conformityLINN Properties. Our opinion is not modified with U.S. generally accepted accounting principles.respect to this matter.

/s/ ERNST & YOUNGPricewaterhouseCoopers LLP

Houston, Texas

April 30, 2012September 24, 2018

Index to Financial Statements

LINN ENERGY, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE

ASSETS ACQUIRED FROM BP AMERICA PRODUCTION COMPANYPROPERTIES CONTRIBUTED BY LINN ENERGY, INC.

Year Ended December 31, 2011, and

Three Months Ended March 31, 2012, and March 31, 2011

(in thousands)(Audited)

 

   Three Months Ended   Year Ended
December 31,
2011
 
   March 31,
2012
   March 31,
2011
   
   (unaudited)   (audited) 

Revenues—oil, natural gas and natural gas liquids sales

  $56,882    $64,544    $290,240  

Direct operating expenses

   25,124     26,520     103,490  

Third party natural gas purchases

   6,188     7,611     37,675  
  

 

 

   

 

 

   

 

 

 

Excess of revenues over direct operating expenses and third party natural gas purchases

  $25,570    $30,413    $149,075  
  

 

 

   

 

 

   

 

 

 
   Eight Months
Ended

August 31, 2017
   Year Ended
December 31,
2016
   Year Ended
December 31,
2015
 
   (in thousands) 

Operating revenues

  $55,573   $35,274   $22,454 

Direct operating expenses

   13,888    12,434    9,448 
  

 

 

   

 

 

   

 

 

 

Excess of revenues over direct operating expenses

  $41,685   $22,840   $13,006 
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of the Statements of Revenues and Direct Operating Expenses.

Index to Financial Statements

LINN ENERGY, LLC

ASSETS ACQUIRED FROM BP AMERICA PRODUCTION COMPANY

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE

Year Ended December 31, 2011, andPROPERTIES CONTRIBUTED BY LINN ENERGY, INC.

Three Months Ended March 31, 2012, and March 31, 2011

Note 1—1 – Basis of Presentation

On February 27, 2012,August 31, 2017, Linn Energy, Inc. (“LINN Energy”), through certain of its subsidiaries, completed the Company entered intotransaction in which LINN Energy contributed certain upstream assets located in Oklahoma (the “LINN Properties”) to Roan Resources LLC (“Roan”). In exchange for their contribution, LINN Energy received a definitive purchase and sale agreement to acquire certain oil and natural gas properties (“Properties”) located primarily50% equity interest in the Hugoton Basin of Southwestern Kansas from BP America Production Company (“BP”). The acquisition closed March 30, 2012, for total consideration of approximately $1.17 billion, and was financed primarily with proceeds from a private offering by the Company of 6.25% senior notes due November 2019 which were issued March 2, 2012.Roan.

The accompanying statements of revenues and direct operating expenses were prepared from the historical accounting records of BP.LINN Energy. These statements are not intended to be a complete presentation of the results of operations of the Properties acquired from BP.LINN Properties. The statements do not include general and administrative expense, effects of derivative transactions, interest income or expense, depreciation, depletion and amortization, any provision for income tax expenses and other income and expense items not directly associated with revenues from the LINN Properties. Historical financial statements reflecting the financial position, results of operations and cash flows required by United States of America generally accepted accounting principles (“GAAP”) are not presented as such information is not readily available and not meaningful to the LINN Properties. Accordingly, the accompanying statements of revenues and direct operating expenses are presented in lieu of the financial statements required underRule 3-05 of Securities and Exchange Commission (“SEC”)Regulation S-X.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions about future events that affect the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuouscontinuing changes in the economic environment will be reflected in the financial statements in future periods.

Revenues representative of the ownership interest in the Properties acquired from BP are presented on a gross basis on the statements of revenues and direct operating expenses. Revenue Recognition

Sales of oil, natural gas and natural gas liquids (“NGL”) are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.

The statements of revenues and directDirect Operating Expenses

Direct operating expenses for the three months ended March 31, 2012,primarily include lease operating expenses, transportation expenses and March 31, 2011, are unaudited, but in the opiniontaxes other than income taxes. Lease operating costs include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Taxes other than income taxes consist primarily of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of the interim periods.severance and ad valorem taxes.

Note 2—2 – Commitments and Contingencies

Pursuant to the terms of the purchase and sale agreement between BP and LINN Energy, certain claims, litigation and liabilities arising in connection with ownership of the acquired Properties prior to the effective date are retained by BP. Notwithstanding this indemnification, LINN EnergyRoan is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the statements of revenues and direct operating expenses.

Index to Financial Statements

LINN ENERGY, LLC

ASSETS ACQUIRED FROM BP AMERICA PRODUCTION COMPANY

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES—ContinuedEXPENSES OF THE

Year Ended December 31, 2011, and

Three Months Ended March 31, 2012, and March 31, 2011

PROPERTIES CONTRIBUTED BY LINN ENERGY, INC. - Continued

 

Note 3—3 – Related Party Transactions

LINN Energy’s subsidiary, Blue Mountain Midstream LLC (“Blue Mountain”), has an agreement in place for the processing of natural gas from certain of the LINN Properties. Transportation expenses related to such processing agreement with Blue Mountain are included in “direct operating expenses” on the statements of revenues and direct operating expenses.

Note 4 – Subsequent Events

ManagementFollowing an internal reorganization, on August 7, 2018, LINN Energy completed the spin-off of Riviera Resources, Inc. (“Riviera”). Pursuant to the spin-off, Blue Mountain is currently a subsidiary of Riviera. The Company has evaluated subsequent events through April 30, 2012,the auditor’s report date, which is the date the statements of revenues and direct operating expenses were available to be issued, and has concluded that no other events need to be reported during this period.

Note 4—5 – Supplemental Oil and Natural Gas Reserve Information (Unaudited)

Estimated Quantities of Proved Oil and Natural Gas Reserves

Estimated quantities of proved oil, natural gas and NGL reserves at December 31, 2011,2016, and 2015, and changes in the reserves during the year,years, are shown below. These reserve estimates have been prepared in complianceaccordance with SEC regulations using the average price during the12-month period, determined as an unweighted average of thefirst-day-of-the-month price for each month.

 

   Natural Gas
(MMcf)
  Oil and  NGL
(MBbls)
  Total
(MMcfe)
 

Proved developed and undeveloped reserves:

    

Beginning of year

   471,795    46,672    751,824  

Revisions of previous estimates

   7,839    811    12,705  

Production

   (29,211  (3,122  (47,942
  

 

 

  

 

 

  

 

 

 

End of year

   450,423    44,361    716,587  
  

 

 

  

 

 

  

 

 

 

Proved developed reserves:

    

Beginning of year

   471,795    46,672    751,824  

End of year

   450,423    44,361    716,587  

Proved undeveloped reserves:

    

Beginning of year

   —      —      —    

End of year

   —      —      —    

Index to Financial Statements

LINN ENERGY, LLC
   Year Ended December 31, 2016 
   Natural
Gas
(MMcf)
   Oil
(MBbls)
   NGL
(MBbls)
   Total
(MMcfe)
 

Proved developed and undeveloped reserves:

        

Beginning of year

   50,503    1,659    3,621    82,185 

Revisions of previous estimates

   2,433    (5   540    5,641 

Extensions, discoveries and other additions

   76,443    5,554    10,150    170,665 

Production

   (6,543   (350   (336   (10,657
  

 

 

   

 

 

   

 

 

   

 

 

 

End of year

   122,836    6,858    13,975    247,834 
  

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

        

Beginning of year

   50,503    1,659    3,621    82,185 

End of year

   79,493    3,486    7,859    147,564 

Proved undeveloped reserves:

        

Beginning of year

   —      —      —      —   

End of year

   43,343    3,372    6,116    100,270 

ASSETS ACQUIRED FROM BP AMERICA PRODUCTION COMPANY

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES—ContinuedEXPENSES OF THE

Year EndedPROPERTIES CONTRIBUTED BY LINN ENERGY, INC. - Continued

   Year Ended December 31, 2015 
   Natural
Gas (MMcf)
   Oil
(MBbls)
   NGL
(MBbls)
   Total
(MMcfe)
 

Proved developed and undeveloped reserves:

        

Beginning of year

   80,474    1,808    5,434    123,923 

Revisions of previous estimates

   (26,792   (368   (1,714   (39,275

Extensions, discoveries and other additions

   1,397    391    198    4,927 

Production

   (4,576   (172   (297   (7,390
  

 

 

   

 

 

   

 

 

   

 

 

 

End of year

   50,503    1,659    3,621    82,185 
  

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves:

        

Beginning of year

   80,474    1,808    5,434    123,923 

End of year

   50,503    1,659    3,621    82,185 

Proved undeveloped reserves:

        

Beginning of year

   —      —      —      —   

End of year

   —      —      —      —   

The year ended December 31, 2011,2016 includes approximately 6 Bcfe of positive revisions of previous estimates (9 Bcfe due to asset performance, partially offset by 3 Bcfe of negative revisions due to lower commodity prices). The year ended December 31, 2015 includes approximately 39 Bcfe of negative revisions of previous estimates (28 Bcfe due to lower commodity prices and 11 Bcfe due to asset performance). Reserve additions from extensions, discoveries and other additions were primarily attributable to LINN Energy’s development drilling of proved acreage. During the year ended December 31, 2016, proved undeveloped reserves increased to 100 Bcfe from zero at December 31, 2015. As a result of the uncertainty regarding LINN Energy’s future commitment to capital, LINN Energy reclassified all of its proved undeveloped reserves to unproved at December 31, 2015.

Three Months Ended March 31, 2012, and March 31, 2011

Standardized Measure of Discounted Future Net Cash Flows

Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the LINN Properties’ proved reserves to theyear-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the CompanyRoan is not subject to federal income taxes.taxes and state taxes are not material.

 

  December 31,
2011
   December 31,
2016
   December 31,
2015
 
  (in thousands)   (in thousands) 

Future estimated revenues

  $3,892,894    $757,928   $241,918 

Future estimated production costs

   (1,740,911   (280,533   (116,098

Future estimated development costs

   (34,753   (116,847   (22,633
  

 

   

 

   

 

 

Future net cash flows

   2,117,230     360,548    103,187 

10% annual discount for estimated timing of cash flows

   (1,138,761   (202,790   (49,071
  

 

   

 

   

 

 

Standardized measure of discounted future net cash flows

  $978,469    $157,758   $54,116 
  

 

   

 

   

 

 

Representative NYMEX prices:(1)

  

Natural gas (MMBtu)

  $4.12  

Representative NYMEX prices:(1)

    

Natural gas (Mcf)

  $2.48   $2.59 

Oil (Bbl)

  $95.84    $42.64   $50.16 

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE

PROPERTIES CONTRIBUTED BY LINN ENERGY, INC. - Continued

 

(1)

In accordance with SEC regulations, reserves at December 31, 2011, were estimated using the average price during the12-month period, determined as an unweighted average of thefirst-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows during the year ended December 31, 2011 (in thousands):flows:

 

Sales of oil and natural gas produced during the period

  $(149,075
  Year Ended
December 31,
2016
   Year Ended
December 31,
2015
 
  (in thousands) 

Beginning balance

  $54,116   $177,138 

Sales and transfers of oil, natural gas and NGL produced during the period

   (22,840   (13,006

Changes in estimated future development costs

   (59   572    (2,214

Net change in sales prices and production costs related to future production

   94,698  

Net change in sales and transfer prices and production costs related to future production

   (1,788   (109,743

Extensions and discoveries

   112,658    9,537 

Net change due to revisions in quantity estimates

   19,811     13,285    (23,028

Accretion of discount

   106,219     5,412    17,714 

Changes in production rates and other

   (155,318   (3,657   (2,282
  

 

   

 

   

 

 

Ending balance

  $157,758   $54,116 
  $(83,724  

 

   

 

 
  

 

 

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many

Index to Financial Statements

judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Index to Financial Statements

Appendix A—GlossaryANNEX A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of Terms

Ascertain terms used in this document, which are commonly used in the oil and natural gas industryindustry:

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions.3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than2-D, ortwo-dimensional, seismic.

Analogous reservoir. Analogous reservoirs, as used in this registration statement,resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following terms havecharacteristics with the following meanings:reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism. For a complete definition of analogous reservoir, refer to the SEC’s RegulationS-X, Rule4-10(a)(2).

Basin.Basin. A large area with a relatively thick accumulation of sedimentary rocks.natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl.Bbl. One stock tank barrel orof 42 U.S. gallons liquid volume.volume used herein in reference to crude oil, condensate or NGLs.

Bcf.Boe. One billion cubic feet.

Bcfe. One billion cubic feetbarrel of oil equivalent, determined usingcalculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil, condensateoil. This is an energy content correlation and does not reflect a value or natural gas liquids.price relationship between the commodities.

Btu. One British thermal unit which is theor Btu. The quantity of heat required to raise the temperature of aone-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.

Completion. Preparation of a well bore and installation of permanent equipment for production of oil, natural gas or NGLs or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Delineation. The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs, refer to the SEC’s RegulationS-X, Rule4-10(a)(7).

Development well.project. The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development well. A well drilled within the proved area of aan oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry holewell or well.. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s RegulationS-X, Rule4-10(a)(10).

Field.E&P.Exploration and production.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s RegulationS-X, Rule4-10(a)(15).

Formation.Fracture stimulation.A stratumprocess whereby fluids mixed with proppants are injected into a wellbore under pressure in order to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.

Formation. A layer of rock which has distinct characteristics that is recognizablediffers from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.nearby rock.

Gross acres or gross wells.wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbls.Held by production. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Liquids. Describes oil, condensate and natural gas liquids.

MBbl. One thousand barrels of crude oil, condensate or other liquid hydrocarbons.NGLs.

MBbls/d.MBoeMBbls. One thousand Boe.

MBoe/d. One thousand Boe per day.

Mcf.Mcf One thousand cubic feet.

Mcfe.. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.gas.

MMBbls.MMBoe. One million barrels of oil or other liquid hydrocarbons.Boe.

MMBoe.MMBtu One million barrels of oil equivalent, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf.

MMBtu.. One million British thermal units.

MMcf.MMcf One million cubic feet.

MMcf/d.MMcf per day.

MMcfe.. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas.

Net acres. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

Net production. Production that is owned by us less royalties and production due to others.

Net revenue interest. A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs. Natural gas to one Bblliquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

NYMEX. The New York Mercantile Exchange.

Operator. The individual or company responsible for the development and/or production of an oil condensate or natural gas liquids.

well or lease.

IndexPlay. A geographic area with hydrocarbon potential.

Production costs. Costs incurred to Financial Statements

operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s RegulationMMcfe/d.MMcfe per day.S-X, Rule4-10(a)(20).

MMMBtu. One billion British thermal units.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

Productive well.well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of suchthe production exceedsexceed production expenses and taxes.

Proration unit. A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developednon-producing. Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved butnon-producing reserves.

Proved developed reserves.reserves. Reserves that can be expected to be recovered through (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared towith the cost of a new well. Additionalwell or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves expected to be obtained throughestimate if the applicationextraction is by means not involving a well.

Proved properties. Properties with proved reserves.

Proved reserves. Those quantities of fluid injection or other improved recovery techniques for supplementing theoil, natural forcesgas and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved reserves. Reserves thatNGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible fromproducible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations priorregulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s RegulationS-X, Rule4-10(a)(22).

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs or PUDs.Reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage areshall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. EstimatesUnder no circumstances shall estimates for proved undeveloped reserves are not attributedbe attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

PV-10. The present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows.

Realized price.The cash market price less all expected quality, transportation and demand adjustments.

Reasonable certainty. A high degree of confidence that quantities will be recovered. For a complete definition of reasonable certainty, refer to the SEC’s RegulationS-X, Rule4-10(a)(24).

Recompletion.Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by anon-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir.Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productiveproducible oil and/or natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reserves.reservoirs.

Resources. Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Royalty interest.. An interest in an oil and natural gas lease that entitlesgives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of such interestthe leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a sharesubsequent owner.

Section. 640 acres.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of the mineral production from a property or to a share of the proceeds there from. It does not contain the rightsacres, e.g.,40-acre spacing, and obligations of operating the property and normally does not bear any of the costs of exploration, development and operation of the property.is often established by regulatory agencies.

Spacing.Spud The number of wells which conservation laws allow to be drilled. Commenced drilling operations on a given area of land.

an identified location.

Index to Financial Statements

Standardized measure of discounted. Discounted future net cash flows. The present value offlows estimated by applying year end prices to the estimated future net revenues to be generated from the production of year end proved reserves, determinedreserves. Future cash inflows are reduced by estimated future production and development costs based onperiod-end costs to determinepre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess ofpre-tax cash inflows over our tax basis in accordance with the regulations of the Securitiesoil and Exchange Commission, without giving effect to non-property related expenses such as general and administrative expenses, debt service, futurenatural gas properties. Future net cash inflows after income tax expenses or depreciation, depletion and amortization;taxes are discounted using ana 10% annual discount rate.

Success rate. The percentage of 10%.wells drilled which produce hydrocarbons in commercial quantities.

Tcfe. One trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Undeveloped acreage.acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas and NGL regardless of whether such acreage contains proved reserves.

Unit or spacing unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Unproved properties. Properties with no proved reserves.

Wellbore Reserves. The hole drilled by the bit that are considered less certainis equipped for oil, natural gas and NGLs production on a completed well. Also called well or borehole.

Working interest. The right granted to be recovered than proved reserves. Unproved reserves may be further sub-classifiedthe lessee of a property to denote progressively increasing uncertainty of recoverabilitydevelop and include probable reserves and possible reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conductown natural gas or other minerals. The working interest owners bear the exploration, development and operating activitiescosts on the property andeither a share of production.cash, penalty or carried basis.

Workover.Workover Maintenance. Operations on a producing well to restore or increase production.

Zone.WTI. West Texas Intermediate.

117,139,511 Shares

LOGO

Roan Resources, Inc.

Class A stratigraphic interval containing one or more reservoirs.

Index to Financial Statements

Linn Co, LLC

Common Shares

Representing Limited Liability Company InterestsStock

 

 

Prospectus

                    , 2012

Barclays

 

 

                    , 2019

 

 

Through and including                     , 2012 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.


Index to Financial Statements

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13.

Other Expenses of Issuance and Distribution.Distribution

SetThe following table sets forth below arean itemized statement of the amounts of all expenses (other than underwriting discounts and the structuring fee) expected to be incurredpayable by the registrants and paid by LINNus in connection with the issuance and distributionregistration of the securities registeredClass A common stock offered hereby. With the exception of the SEC registration fee and the FINRA filing fee and the NASDAQ listing fee, the amounts set forth below are estimates. The selling stockholders will not bear any portion of such expenses.

 

SEC registration fee

    $250,262.02 

FINRA filing fee

  $114,600  

NASDAQ listing fee

  $75,500  

Accounting fees and expenses

   * 

Legal fees and expenses

   * 

Printing and engraving expenses

   *     * 

Fees and expenses of legal counsel

   *  

Accounting fees and expenses

   *  

Transfer agent and registrar fees

   *  

Miscellaneous

   *     * 
  

 

   

 

 

Total

   *    $* 
  

 

   

 

 

 

*

To be filedprovided by amendment.amendment

 

Item 14.

Indemnification of Directors and Officers.Officers

Section 145 of the DGCL provides that a corporation may indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise), against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. A similar standard is applicable in the case of derivative actions (i.e., actions by or in the right of the corporation), except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation.

Our limitedcertificate of incorporation and our bylaws will contain provisions that limit the liability company agreement provide that we will generally indemnify officers and members of our board of directors and officers for monetary damages to the fullest extent permitted by the law against all losses, claims,DGCL. Consequently, our directors will not be personally liable to us or our stockholders for monetary damages or similar events. Our limited liability company agreement is attachedfor breach of fiduciary duty as an exhibit hereto. Subjecta director, except with respect to liability:

for any terms, conditions or restrictions set forth in our limited liability company agreement, Section 18-108breach of the Delaware Limited Liability Company Act empowers a Delawaredirector’s duty of loyalty to our company or our stockholders;

for any act or omission not in good faith or that involve intentional misconduct or knowing violation of law;

under Section 174 of the DGCL regarding unlawful dividends and stock purchases; or

for any transaction from which the director derived an improper personal benefit.

Any amendment to, or repeal of, these provisions will not eliminate or reduce the effect of these provisions in respect of any act, omission or claim that occurred or arose prior to that amendment or repeal. If the DGCL is amended to provide for further limitations on the personal liability of directors or officers of corporations, then the personal liability of our directors and officers will be further limited liability companyto the fullest extent permitted by the DGCL.

II-1


In addition, we entered into indemnification agreements with our current directors containing provisions that are in some respects broader than the specific indemnification provisions contained in the DGCL. The indemnification agreements will require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and hold harmlessto advance their expenses incurred as a result of any member or manager or other person from andproceeding against all claims and demands whatsoever.them as to which they could be indemnified. We have also enteredintend to enter into individual indemnityindemnification agreements with eachour future directors.

We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities arising under the Securities Act and the Exchange Act, that may be incurred by them in their capacity as such.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of our executive officersthe SEC, such indemnification is against public policy as expressed in the Securities Act and directors which supplement the indemnification provisions in our limited liability company agreement.is therefore unenforceable.

 

Item 15.

Recent Sales of Unregistered Securities

LinnCo’s initial voting share was soldIn connection with our incorporation on September 19, 2018, under the laws of the State of Delaware, we issued 1,000 shares of our Class A common stock to Linn Energy, LLCInc. for $1,000 on April 30, 2012. Such sale was completed without registration under the Securities Actan aggregate purchase price of $1.00. These securities were offered and sold by us in reliance upon the exemption from the registration requirements provided by Section 4(2)4(a)(2) of the Securities Act. These shares were redeemed for nominal value in connection with the Reorganization.

Further, on September 24, 2018, in connection with the closing of the Reorganization and pursuant to the terms of the Master Reorganization Agreement and the Roan Holdco Merger Agreement, we issued 76,269,766 shares of our Class A common stock to Roan Holdings. This issuance of our Class A common stock did not involve any underwriters, underwriting discounts or commissions or a public offering and such issuance was exempt from registration requirements pursuant to Section 4(a)(2) of the Securities Act.

 

Item 16.

Exhibits and Financial Statement Schedules.Schedules

The following documents are filed as exhibits to this registration statement:(a) Exhibits.

 

NumberExhibit
No.

  

Description

    2.1Linn Merger Agreement, dated September 24, 2018, by and among Linn Energy, Inc., Roan Resources, Inc. and Linn Merger Sub #2, LLC (incorporated by reference to Exhibit 2.1 to Form8-K filed on September 24, 2018)
    1.1*2.2  

Roan Merger Agreement, dated September 24, 2018, by and among Roan Holdings, LLC, Roan Holdings Holdco, LLC, Roan Resource, Inc. and Linn Merger Sub #3, LLC (incorporated by reference to Exhibit 2.2 to Form of Underwriting Agreement

8-K filed on September 24, 2018)
    3.1  

Second Amended and Restated Certificate of FormationIncorporation of Linn Co, LLC

Roan Resources, Inc. (incorporated by reference to Exhibit 3.1 to Form8-K filed on September 27, 2018)
    3.2  

CertificateSecond Amended and Restated Bylaws of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC)Roan Resources, Inc. (incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)
  3.3

Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to Form8-K filed on September 27, 2018)
    4.1Registration StatementRights Agreement, dated September 24, 2018, by and among Roan Resources, Inc. and each of the other parties listed on the signature page thereto (incorporated by reference to Exhibit 4.1 to Form S-1 (File No. 333-125501)8-K filed on September 24, 2018)
    4.2Stockholders Agreement, dated September  24, 2018, by Linn Energy,and among Roan Resources, Inc., the Existing LINN Owners (as defined therein), Roan Holdings, LLC and any other persons signatory thereto from time to time (incorporated by reference to Exhibit 4.2 to Form8-K filed on June 3, 2005)September 24, 2018)

II-2


  3.4*

Exhibit
No.

  

Form of Limited Liability Company Agreement of Linn Co, LLC

II-1


Index to Financial Statements

Number

Description

    5.1**Opinion of Vinson & Elkins L.L.P.
  3.510.1  

Credit Agreement, dated September  5, 2017, by and among Citibank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to Form8-K filed on September 24, 2018)
  10.2  ThirdAmendment No. 1 to Credit Agreement, dated April 9, 2018 (incorporated by reference to Exhibit 10.2 to Form8-K filed on September 24, 2018)
  10.3Amendment No. 2 to Credit Agreement, dated May 30, 2018 (incorporated by reference to Exhibit 10.3 to Form8-K filed on September 24, 2018)
  10.4Amendment No. 3 to Credit Agreement, dated September 27, 2018 (incorporated by reference to Exhibit 10.1 to Form8-K filed on September 27, 2018)
†10.5Roan Resources, Inc. Amended and Restated Management Incentive Plan, dated September 24, 2018 (incorporated by reference to Exhibit 10.4 to Form8-K filed on September 24, 2018)
†10.6Form of Performance Share Unit Grant Notice and Performance Share Unit Award Agreement pursuant to the Roan Resources, Inc. Amended and Restated Management Incentive Plan (incorporated by reference to Exhibit 10.5 to Form8-K filed on September 24, 2018)
  10.7Voting Agreement, dated September 24, 2018, by and among Roan Resources, Inc., the Existing LINN Owners (as defined therein), Roan Holdings, LLC and any other persons signatory thereto from time to time (incorporated by reference to Exhibit 10.6 to Form8-K filed on September 24, 2018)
  10.8Second Amended and Restated Limited Liability Company Agreement of Linn Energy,Roan Resources LLC dated September 3, 2010 (incorporated herein by reference to Exhibit 3.110.7 to Current ReportForm8-K filed on September 24, 2018)
†10.9Letter Agreement, dated April 13, 2019, between Roan Resources, Inc. and Joseph Mills (incorporated by reference to Exhibit 10.1 to Form 8-K filed on April 18, 2019)
†10.10Employment Agreement, dated June  18, 2018, between Roan Resources LLC and David Edwards (incorporated by reference to Exhibit 10.9 to Form8-K filed on September 7, 2010)24, 2018)
†10.11Employment Agreement, dated November  6, 2017, between Roan Resources LLC and Joel Pettit (incorporated by reference to Exhibit 10.10 to Form8-K filed on September 24, 2018)
†10.12Employment Agreement, dated November  6, 2017, between Roan Resources LLC and Greg Condray (incorporated by reference to Exhibit 10.11 to Form8-K filed on September 24, 2018)
†10.13Employment Agreement, dated September  17, 2018, between Roan Resources LLC and David Treadwell (incorporated by reference to Exhibit 10.12 to Form8-K filed on September 24, 2018)
  10.14Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Matthew Bonanno (incorporated by reference to Exhibit 10.14 to Form8-K filed on September 24, 2018)
  10.15Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Evan Lederman (incorporated by reference to Exhibit 10.15 to Form8-K filed on September 24, 2018)
  10.16Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and John Lovoi (incorporated by reference to Exhibit 10.16 to Form8-K filed on September 24, 2018)
  10.17Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Paul B. Loyd Jr. (incorporated by reference to Exhibit 10.17 to Form8-K filed on September 24, 2018)
  10.18Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Michael Raleigh (incorporated by reference to Exhibit 10.18 to Form8-K filed on September 24, 2018)

II-3


  5.1*

Exhibit No.

 

Opinion of Baker Botts L.L.P. as to the legality of the securities being registeredDescription

  8.1*10.19 

Opinion of Baker Botts L.L.P. relatingIndemnification Agreement, dated September  24, 2018, between Roan Resources, Inc. and Andrew Taylor (incorporated by reference to tax matters

Exhibit 10.19 to Form8-K filed on September 24, 2018)
10.1*  10.20 

Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Anthony Tripodo (incorporated by reference to Exhibit 10.20 to Form of Omnibus Agreement

8-K filed on September 24, 2018)
  10.21Indemnification Agreement, dated November 5, 2018, between Roan Resources, Inc. and Joseph  A. Mills (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 6, 2018)
  10.22Tax Matters Agreement, dated August 7, 2018, by and among Linn Energy, Inc., Riviera Resources,  Inc. and the Riviera Resources, Inc. Subsidiaries (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Linn Energy, Inc. on August 10, 2018)
  10.23†Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement pursuant to the Roan Resources, Inc. Amended and Restated Management Incentive Plan (incorporated by reference to Exhibit 10.25 to Form 10-K filed on April 1, 2019)
  10.24Amendment No. 4 to Credit Agreement, dated March 13, 2019 (incorporated by reference to Exhibit  10.1 to Form 8-K filed on March 13, 2019)
  10.25Employment Agreement, dated April 29, 2019, between Roan Resources LLC and Amber Bonney (incorporated by reference to Exhibit 10.26 to Form 10-K/A filed on April 30, 2019)
  10.26Separation Agreement and General Release of Claims between Roan Resources LLC and Tony C. Maranto, dated April 26, 2019 (incorporated by reference to Exhibit 10.27 to Form 10-K/A filed on April 30, 2019)
21.1 

List of Subsidiaries of Linn Energy, LLCRoan Resources, Inc. (incorporated herein by reference to Exhibit 21.1 to Annual Report on Form 10-K for the year ended December 31, 2011,8-K filed on February 23, 2012)September 24, 2018)
23.1  23.1* 

Consent of KPMGPricewaterhouseCoopers LLP

23.2  23.2* 

Consent of Ernst & YoungPricewaterhouseCoopers LLP

23.3  23.3* 

Consent of DeGolyer &and MacNaughton

23.4** 

Consent of Baker BottsVinson & Elkins L.L.P. (contained(included in Exhibit 5.1)

23.5*  24.1** 

Consent of Baker Botts L.L.P. (contained in Exhibit 8.1)

24.1

PowersPower of Attorney (contained(included on the signature page to this Registration Statement)

hereto)
99.1 

2011 Report of DeGolyer &and MacNaughton, Summary of Reserves at December 31, 2018 (incorporated herein by reference to Exhibit 99.1 to Annual Report on Form10-K for the year ended December 31, 2011, filed on February 23, 2012)April 1, 2019)
  101.INS*XBRL Instance Document.
  101.SCH*XBRL Taxonomy Extension Schema Document.
  101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document.
  101.DEF*XBRL Taxonomy Extension Definition Linkbase Document.
  101.LAB*XBRL Taxonomy Extension Labels Linkbase Document.
  101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document.

 

Compensatory plan or arrangement.

*To be filed by amendment

Filed herewith.

**

Previously filed.

Item 17.Undertakings.

The undersigned registrant hereby undertakes to provide to(b) Financial Statement Schedules. Financial statement schedules are omitted because the underwriters at the closing specifiedrequired information is not applicable, not required or included in the underwriting agreement certificatesfinancial statements or the notes thereto included in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.prospectus that forms a part of this registration statement.

II-4


Item 17.

Undertakings

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining liability under the Securities Act, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness.Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(1)For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(2)For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement (i) to include any prospectus required by section 10(a)(3) of the Securities Act of 1933; (ii) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement, and (iii) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(4) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

 

II-2II-5


The undersigned registrant undertakes to send to each shareholder, at least on an annual basis, a detailed statement of any transactions with Linn Energy, LLC or any of its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Linn Energy, LLC or any of its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the shareholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

The undersigned registrant hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreements certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

II-3


Index to Financial Statements

SIGNATURES

Pursuant to the requirements of the Securities Act, of 1933, as amended, the registrant has duly caused this Registration Statementregistration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston,Oklahoma City, State of Texas,Oklahoma, on June 25, 2012.May 28, 2019.

 

LINN CO, LLC

ROAN RESOURCES, INC.

By:

 /s/ Kolja RockovJoseph A. Mills
Name: 

Name: Kolja Rockov

Joseph A. Mills

Title:Executive Vice President and Chief

          Financial Officer

Chairman

Each person whose signature appears below appoints Mark E. Ellis, Kolja Rockov and Candice Wells, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act, of 1933, as amended, this Registration Statementregistration statement has been signed by the following persons in the capacities and the dates indicated.indicated on May 28, 2019.

 

NameSignature

  

Title

Date

/s/ Mark E. Ellis        Joseph A. Mills

Mark E. Ellis

Chairman, President and Chief Executive Officer; DirectorJune 25, 2012

/s/    Kolja Rockov         

Kolja RockovJoseph A. Mills

  Executive Vice President and Chief Financial OfficerJune 25, 2012Chairman
(Principal Executive Officer)

/s/ David B. Rottino         M. Edwards

David B. RottinoM. Edwards

  Senior Vice President and

Chief AccountingFinancial Officer

June 25, 2012

(Principal Financial Officer)

/s/ George A. Alcorn         Amber N. Bonney

George A. AlcornAmber N. Bonney

  Independent DirectorJune 25, 2012

Chief Accounting Officer

(Principal Accounting Officer)

/s/    David D. Dunlap         *

David D. DunlapMatthew Bonanno

  Independent DirectorJune 25, 2012

/s/    Terrence S. Jacobs         *

Terrence S. JacobsEvan Lederman

  Independent DirectorJune 25, 2012

II-4


Index to Financial Statements

Name*

John V. Lovoi

  

Title

Date

Director

/s/    Michael C. Linn         *

Michael C. LinnPaul B. Loyd, Jr.

  DirectorJune 25, 2012

/s/    Joseph*

Michael P. McCoy         

Joseph P. McCoyRaleigh

  Independent DirectorJune 25, 2012

/s/    Jeffrey C. Swoveland         

Jeffrey C. Swoveland

Independent DirectorJune 25, 2012

 

II-5II-6


Index to Financial Statements

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on June 25, 2012.

LINN ENERGY, LLCSignature

Title

By:

*

Andrew Taylor

  /s/    Kolja Rockov        

Director

Name: Kolja Rockov

Title: Executive Vice President and Chief

          Financial Officer

Each person whose signature appears below appoints Mark E. Ellis, Kolja Rockov and Candice Wells, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

Name*

Anthony Tripodo

  

Title

Date

Director

/s/    Mark E. Ellis         

Mark E. Ellis

* Chairman, President and Chief Executive Officer; DirectorJune 25, 2012/s/ David M. Edwards

/s/    Kolja Rockov         

Kolja Rockov

Executive Vice President and Chief Financial OfficerJune 25, 2012David M. Edwards

/s/    David B. Rottino         

David B. Rottino

Senior Vice President of Finance, Business Development and Chief Accounting OfficerJune 25, 2012

/s/    George A. Alcorn         

George A. Alcorn

Independent DirectorJune 25, 2012

/s/    David D. Dunlap         

David D. Dunlap

Independent DirectorJune 25, 2012

/s/    Terrence S. Jacobs         

Terrence S. Jacobs

Independent DirectorJune 25, 2012Attorney-in-Fact

II-6


Index to Financial Statements

Name

Title

Date

/s/    Michael C. Linn         

Michael C. Linn

DirectorJune 25, 2012

/s/    Joseph P. McCoy         

Joseph P. McCoy

Independent DirectorJune 25, 2012

/s/    Jeffrey C. Swoveland         

Jeffrey C. Swoveland

Independent DirectorJune 25, 2012

 

II-7