Loading...
Docoh

Pressburg (ROAN)

Filed: 15 May 19, 7:55am








 UNITED STATES 
SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549 
 FORM 10-Q 
     
x     QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2019
¨ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to ___________
Commission File Number: 001-32720
 Roan Resources, Inc. 
 (Exact Name of Registrant as Specified in its Charter) 
   
Delaware 83-1984112
(State or Other Jurisdiction
of Incorporation)
 (IRS Employer
Identification No.)
   
14701 Hertz Quail Springs Pkwy
Oklahoma City, OK
 73134
(Address of Principal Executive Offices) (Zip Code)
(405) 896-8050
(Registrant’s Telephone Number, including Area Code)
   
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x    No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12 b-2 of the Exchange Act. (Check One):
Large Accelerated Filer ¨
 
Accelerated Filer ¨
   Non-Accelerated Filer x
 
 Smaller 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 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ¨   No  x
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x   No  ¨
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each ClassTrading SymbolName of Each Exchange on Which Registered
Class A Common Stock, par value $0.001 per shareROANNew York Stock Exchange
   
As of May 10, 2019, there were 152,539,532 shares of Class A common stock, par value $0.001 per share, outstanding.









TABLE OF CONTENTS








    







CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (the “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, 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 Quarterly Report, 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 carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018 (our “Annual Report on Form 10-K”) filed with the Securities and Exchange Commission (the “SEC”) and in Part II, Item 1A. “Risk Factors” of this Quarterly Report.
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 operating results including initial production values and liquid yields in our type curve areas;
the costs, terms and availability of gathering, processing, fractionation and other midstream services; and
our plans, objectives, expectations and intentions that are not historical.

These forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incidental 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 in Part II, Item 1A. “Risk Factors” of this Quarterly Report.

1



GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
Analogous reservoir. Analogous reservoirs, as used in 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 characteristics with the 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 Regulation S-X, Rule 4-10(a)(2).
Basin. A large natural depression on the earth’s surface in which sediments, generally brought by water, accumulate.
Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Btu. British thermal unit. The quantity of heat required to raise the temperature of a one pound mass of water from 58.5 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.
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 Regulation S-X, Rule 4-10(a)(7).
Development 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.
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 well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production 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 Regulation S-X, Rule 4-10(a)(10).
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature 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 Regulation S-X, Rule 4-10(a)(15).

2



Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Held by production or HBP. 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.
Liquids. Describes oil, condensate and natural gas liquids.
MBbls. One thousand barrels of crude oil, condensate or NGLs.
MBoe. One thousand Boe.
MBoe/d. One thousand Boe per day.
Mcf. One thousand cubic feet of natural gas.
MMBtu. One million British thermal units.
MMcf. One million cubic feet 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% working interest in 100 acres owns 50 net acres.
Net production. Production that is owned by us less royalties and production due to others.
NGLs or Natural gas liquids. 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 or natural gas well or lease.
Play. A geographic area with hydrocarbon potential.
Production costs. Costs incurred to 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 Regulation S-X, Rule 4-10(a)(20).
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 developed 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 with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved properties. Properties with proved reserves.

3



Proved reserves. Those quantities of oil, natural gas and NGLs, 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. 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 Regulation S-X, Rule 4-10(a)(22).
Proved undeveloped reserves or PUDs. 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 shall 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. Under no circumstances shall estimates for proved undeveloped reserves be 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.
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 Regulation S-X, Rule 4-10(a)(24).
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 a non-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. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other 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.
Spacing. The distance between wells producing from the same reservoir.
Unproved properties. Properties with no proved reserves.
Wellbore. The hole drilled by the bit that is equipped for oil, natural gas and NGL production on a completed well. Also called well or borehole.

4



Working interest. The right granted to the lessee of a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
Workover. Operations on a producing well to restore or increase production.
WTI. West Texas Intermediate.

5


PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Roan Resources, Inc.
Condensed Consolidated Balance Sheets (Unaudited)





 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 sales52,506
 55,564
Affiliates5,175
 9,669
Joint interest owners and other, net148,051
 133,387
Prepaid drilling advances23,132
 28,977
Derivative contracts14,104
 82,180
Other current assets10,179
 6,655
Total current assets255,336
 323,315
Noncurrent assets   
Oil and natural gas properties, successful efforts method2,801,145
 2,628,333
Accumulated depreciation, depletion, amortization and impairment(282,541) (230,836)
Oil and natural gas properties, net2,518,604
 2,397,497
Derivative contracts4,529
 20,638
Other12,967
 7,659
Total assets$2,791,436
 $2,749,109
LIABILITIES AND EQUITY   
Current liabilities   
Accounts payable$121,110
 $49,746
Accrued liabilities131,403
 176,494
Accounts payable and accrued liabilities – Affiliates
 8,577
Revenue payable95,104
 97,963
Drilling advances36,149
 31,058
Derivative contracts5,583
 845
Other current liabilities2,552
 790
Total current liabilities391,901
 365,473
Noncurrent liabilities   
Long-term debt602,639
 514,639
Deferred tax liabilities, net333,966
 356,862
Asset retirement obligations16,967
 16,058
Derivative contracts241
 141
Other5,679
 902
Total liabilities1,351,393
 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, 2018153
 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
 
Additional paid-in capital1,649,466
 1,646,401
Accumulated deficit(209,576) (151,520)
      Total equity1,440,043
 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.

6



Roan Resources, Inc.
Condensed Consolidated Statements of Operations (Unaudited)



  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.

7



Roan Resources, Inc.
Condensed Consolidated Statements of Changes in Equity (Unaudited)



 Stockholders’ Equity  
 Common Stock (Shares)Common StockAdditional Paid-in CapitalAccumulated DeficitMembers’ EquityTotal 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, 2018152,540
$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, 2019152,540
$153
$1,649,466
$(209,576)$
$1,440,043
       



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8



Roan Resources, Inc.
Condensed Consolidated Statements of Cash Flows (Unaudited)


 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 accretion41,572
 21,865
Unproved leasehold amortization and impairment11,331
 7,350
Gain on sale of other assets(664) 
Amortization of deferred financing costs537
 145
Loss on derivative contracts83,642
 9,614
Net cash received (paid) upon settlement of derivative contracts2,549
 (4,138)
Equity-based compensation3,065
 2,292
Deferred income taxes(22,897) 
   Other1,514
 
Changes in operating assets and liabilities increasing (decreasing) cash:   
Accounts receivable and other assets(14,770) (56,369)
Accounts payable and other liabilities15,792
 (24,614)
Net cash provided by (used in) operating activities63,615
 (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 assets1,264
 
Net cash used in investing activities(158,200) (111,254)
Cash flows from financing activities   
Proceeds from borrowings88,000
 121,300
Other1,891
 
Net cash provided by financing activities89,891
 121,300
Net (decrease) increase in cash and cash equivalents(4,694) 1,272
Cash and cash equivalents, beginning of period6,883
 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 of non-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.

9



Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements



Note 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.” See Note 10 – Equity for further discussion of the Reorganization transaction. The accompanying historical financial statements for the three months ended March 31, 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 among 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 an area-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”). See Note 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 – Summary of Significant Accounting Policies

For a description of the Company’s significant accounting policies, refer to Note 2 to the Company’s 2018 audited financial statements included in the Annual Report on Form 10-K. The accompanying condensed consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).

Certain amounts in the 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 Roan Inc. and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated.

Interim Financial Statements

The accompanying condensed consolidated financial statements as of December 31, 2018 were derived from the annual financial statements included in the Annual Report on Form 10-K. The unaudited interim condensed consolidated financial statements for the three months ended March 31, 2019 and 2018 were prepared by the Company 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

10


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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 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 these estimates.

Recent Accounting Standards Issued

In February 2016, the FASB issued ASU 2016-02, 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 a right-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 ASU 2018-11 Leases (Topic 842): Targeted Improvements as of January 1, 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. See Note 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 ASU 2018-11 Leases (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 ASU 2018-01 Leases (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 practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.


11


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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 adoption of this standard resulted in the Company recognizing right-of-use assets and lease liabilities for certain of its operating leases on the accompanying condensed consolidated balance sheet as of March 31, 2019. The Company has no finance leases. The following table shows the impact of the adoption of ASC 842 on the Company’s current period balance sheet as compared to the previous lease accounting standard, ASC Topic 840, Leases (“ASC 840”):

 As of March 31, 2019
 Under ASC 842Under ASC 840Increase/(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 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 Company capitalizes both lease classifications on its consolidated balance sheets through a right-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 and non-lease components. For all asset classes with multiple component types, the Company has utilized the practical expedient that exempts it from separating lease components from non-lease components. Accordingly, the Company accounts for the lease and non-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


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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 and non-cancelable leases to support our operations.

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 a non-cancelable primary term of twelve months and continue thereafter on a month-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 primary non-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 a month-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.


13


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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 for non-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 Revenue from Contracts with Customers (Topic 606) (“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 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 as of 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.


14


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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:

 March 31, 2019 December 31, 2018
 (in thousands)
Oil and natural gas properties   
Proved$1,730,526
 $1,538,379
Unproved1,070,619
 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

For 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.

Note 6 – Asset Retirement Obligations

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 acquired667
Revisions in estimated cash flows
Liabilities settled(87)
Accretion expense278
Asset retirement obligation, March 31, 201917,706
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 $750.0 million credit agreement with an initial borrowing base of $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

15


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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 (“LIBOR”) or 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 the one-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 LevelUtilizationLIBOR MarginABR MarginCommitment 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; (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 exclude non-cash assets and liabilities under ASC Topic 815 Derivatives and Hedging and ASC Topic 410 Asset 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

16


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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. See Note 9 – Fair Value Measurements for 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 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.


17


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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.

18


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 to Note 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’s non‑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

19


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


units is determined using a Monte Carlo simulation model and is classified as a Level 3 measurement. Please refer to Note 11 – Equity Compensation for additional discussion.

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. Additionally, Roan LLC issued 1.5 billion LLC Units, which represented a 50% equity interest, 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.

In March 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 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.

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

20


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


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 three months ended March 31, 2019:
 Number of
PSUs
 Weighted
Average Fair
Value
 Total Fair
Value ($ in thousands)
Outstanding at December 31, 20181,158,750
 $30.95
 $35,864
Granted
 
 
Vested
 
 
Forfeited
 
 
Outstanding at March 31, 20191,158,750
 $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 statements of 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 Class A common stock on the grant date of the 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, 201811,800
 $16.95
 $200
Granted
 
 
Vested
 
 
Forfeited
 
 
Outstanding at March 31, 201911,800
 $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

21


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


expense as of March 31, 2019 for all outstanding RSUs was $0.1 million and will be recognized over a weighted-average remaining period of 0.58 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.

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 Roan LLC. 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 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, 2018, Roan LLC incurred approximately $7.5 million for charges related to the services provided under the MSAs, which were recorded in general and administrative expenses in the condensed consolidated statements of 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

As 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. See Note 10 – Equity for 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 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 Company’s portion of the production sold to Blue Mountain. Sales to Blue Mountain are reflected as Natural gas sales – Affiliates and Natural gas liquids sales – Affiliates in the accompanying condensed consolidated statements of operations. See further discussion of this gas dedication agreement in Note 14 – Commitments and Contingencies.

Corporate 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 $0.3 million during the three months

22


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


ended March 31, 2019 under this lease. Total remaining payments under the lease are $7.8 million, excluding the Company’s portion of the operating expenses of the building.

Tax Matters Agreement

In conjunction with the Reorganization, the Company entered into a tax matters agreement (“TMA”) with Riviera. See Note 13 – Income Taxes for further discussion of the TMA and the related amount paid to Riviera.
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.

Note 13 – Income Taxes

As discussed in Note 1 – Business and Organization, Roan Inc. 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 Inc. is a corporation and subject to U.S. federal and state income tax.

The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The Company’s effective combined U.S. federal and state income tax rate for the three months ended March 31, 2019 was 28.3% based on estimated net income for the year. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate.

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 taxes of Linn Energy, Inc. prior to the spinoff of Riviera from Linn Energy, Inc. As a result of the TMA and the 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 $7.6 million to Riviera during the three months ended March 31, 2019.

Note 14 – Commitments and Contingencies

Lease Commitments

As discussed in Note 3 - Lease Accounting, we lease certain office buildings, drilling rigs, and field equipment under cancelable and non-cancelable leases to support our operations.

The Company’s lease costs for the three months ended March 31, 2019 included operating lease costs of $0.4 million and short-term lease costs of $33.5 million. Short-term lease costs exclude leases with a contract term of one month or less. Included in short-term lease costs is $32.2 million of gross costs related to the

23


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


Company’s drilling rig leases. The Company’s portion of the drilling rig costs are capitalized to oil and 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, 2019 were $0.3 million.

The Company’s condensed consolidated balance sheet as of March 31, 2019 included lease assets and liabilities as follows (in thousands):
Operating Leases 
Operating lease right of use assets$6,068
  
Current operating lease liabilities$1,813
Noncurrent operating lease liabilities5,326
Total operating lease liabilities$7,139

The weighted average remaining lease term for our operating leases is 4.1 years and the 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
20202,046
20212,136
20222,229
2023456
Thereafter171
Total lease payments8,422
Less imputed interest(1,283)
Total$7,139

Litigation

The Company is party to lawsuits arising in the ordinary course of business, including, but not limited to, commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The Company cannot 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 material adverse impact on the Company’s financial condition.

Due to the 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 against the Company, if decided adversely, will have a material adverse effect on the Company’s financial condition, cash flows or results of operations.

24


Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements



Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. At March 31, 2019, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Natural Gas Dedication Agreements

The Company has dedicated its natural gas production from the oil and natural gas properties 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 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 result, the Company has accrued $0.4 million for its share of the estimated shortfall deficiency fees as of March 31, 2019. The accrued liability is included in other noncurrent liabilities in the accompanying condensed consolidated balance sheet. If the Company 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 end of the commitment period.


25


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of the Company should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this report as well as our audited consolidated financial statements and notes included in our Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are subject to risk and uncertainties, most of 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. Please refer to Part II, Item 1A. “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for additional information regarding these risks and uncertainties. In light of these risks and uncertainties, 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.

Roan Inc. was incorporated in September 2018 to serve as a holding company, and prior to the Reorganization, had no operations, assets or liabilities. The historical financial and operating information included in this Quarterly Report, (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the information of Roan LLC, our accounting predecessor.

Overview

We are an independent oil and natural gas company focused on the development of our 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 to deliver compelling economic rates of return on a risk adjusted basis. Our objective is to maximize shareholder value and corporate returns by generating steady production growth, strong pre-tax margins and significant cash flow. 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.

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.

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Corporate Reorganization

On September 24, 2018, we completed the Reorganization, as a result of which Roan LLC, our accounting predecessor, became a wholly owned subsidiary of Roan Inc. Roan Inc. was incorporated to serve as a holding

26


company and, prior to the Reorganization, had no previous operations, assets or liabilities. For more information on our Reorganization, please see Note 1 – Business and Organization.

The historical financial and operating information included in this Quarterly Report, (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the information of Roan LLC, our accounting predecessor.

Public Company Expenses

Subsequent to the Reorganization, we incur direct, incremental general and administrative expenses as a result of being 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 general and administrative 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. 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 federal 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.

Financial and Operational Performance

Our financial and operational performance for the three months ended March 31, 2019 included the following highlights:
Net loss was $58.1 million for the three months ended March 31, 2019, as compared to net income of $35.1 million for the three months ended March 31, 2018. The net loss was primarily due to:

$2.4 million decrease in total oil, natural gas and NGL sales, primarily as a result of a decrease in realized prices during the three months ended March 31, 2019 partially offset by an increase in production volumes.
$74.0 million increase in loss on derivative contracts during the three months ended March 31, 2019 as a result of increases in oil prices during this period;
$6.5 million increase in production expenses, primarily related to an increase in production volumes for the three months ended March 31, 2019;
$4.6 million increase in exploration expenses, primarily related to increased unproved leasehold amortization during the three months ended March 31, 2019;
$19.7 million increase in depreciation, depletion, amortization and accretion, primarily due to an increase in production volumes and a higher depletion rate due to increases in capital expenditures;
    
partially offset by:
$22.9 million income tax benefit during the three months ended March 31, 2019.

27



Average daily sales volumes were 48.9 MBoe for the three months ended March 31, 2019, an increase of 30% compared to 37.7 MBoe during the same period in 2018.
Drilled or participated in 24 gross (13 net) wells with first production during the first three months of 2019.

Sources of Revenue

Our revenues are derived 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 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 our derivative contracts, for the periods presented:
 Three Months Ended March 31,
 2019 2018
Revenues   
   Oil sales61% 63%
   Natural gas sales22% 17%
   Natural gas liquid sales17% 20%

Realized Prices on the Sales of Oil, Natural Gas and NGL 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. From time to time, we enter into derivative arrangements for our oil and natural gas production to mitigate the impact of price volatility on our business. See Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk for further discussion of the risks related to commodity price exposure and our derivative contracts.
Pricing for certain of our natural gas contracts are based on Oklahoma indexes, including ONEOK Gas Transportation, Natural Gas Pipeline Company of America Mid-Continent, Panhandle Eastern Pipeline and Southern Star Central Gas Pipeline 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.




28



Oil and natural gas prices have been subject to significant fluctuations during the past several years. The following table sets forth the average NYMEX oil and natural gas prices for the three months ended March 31, 2019 and 2018:
 Three Months Ended March 31,
 2019 2018
Average NYMEX prices   
Oil (Bbl)$54.85
 $62.86
Natural gas (MMcf)$3.02
 $3.19

Results of Operations

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

The following table presents selected financial and operating information for the periods presented.
 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.


29


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
Revenues(in thousands)
Oil sales$60,571
 $63,692
Natural gas sales21,781
 16,890
Natural gas liquid sales16,187
 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

30


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 taxes5,039
 2,386
Exploration expenses12,488
 7,850
Depreciation, depletion, amortization and accretion41,572
 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 taxes1.14
 0.70
Exploration expenses2.84
 2.31
Depreciation, depletion, amortization and accretion9.44
 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, 2019 and 2018 include $3.1 million, or $0.70 per Boe, and $2.3 million, or $0.67 per Boe, of equity-based compensation expense, respectively. General and administrative expenses for the three months ended March 31, 2019 includes $1.5 million, or $0.34 per Boe, of bad debt expense.

Production 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 direct 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. Production taxes are paid on produced oil, natural gas, and NGLs based primarily on a percentage of sales revenues from production sold at fixed rates established by federal, state or local taxing authorities. Production taxes were $5.0 million for the three months ended March 31, 2019, an increase of

31


$2.7 million, or 111%, from $2.4 million for the three months ended March 31, 2018. Production taxes primarily increased due to increased production tax rates, which became effective in July 2018.

Exploration expenses. These are primarily geological and geophysical costs that include seismic survey costs, amortization of the costs of unproved properties assessed for impairment on a group basis, costs of carrying and retaining unproved properties, and costs related to unsuccessful leasing efforts. Exploration expenses were $12.5 million for the three months ended March 31, 2019, an increase of $4.6 million, or 59%, from $7.9 million for the three months ended March 31, 2018. Exploration expenses for both periods primarily consisted of unproved leasehold amortization. Unproved leasehold amortization is calculated by considering our drilling plans and the 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 the depletion rate for our oil and natural gas properties and to a lesser 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 $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, 2019, general and administrative expenses included salaries and benefits of $8.7 million, equity-based compensation expense of $3.1 million and bad debt expense of $1.5 million. During the three months ended March 31, 2018, 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 the three months ended March 31, 2019 was $6.7 million as compared to $1.8 million for the three months ended March 31, 2018. This increase was due to increased borrowings outstanding during the three months ended March 31, 2019 as compared to the three months ended March 31, 2018.

Income tax benefit. The income tax benefit for the three months ended March 31, 2019 was $22.9 million and is the result of our effective tax rate applied to our net loss for the quarter. As Roan LLC was a flow-through entity for income tax purposes, there was no income tax expense or benefit recorded for the three months ended March 31, 2018.


32


Liquidity and Capital Resources

Our primary sources of liquidity have been borrowings under our Credit Facility and cash flows from operations. Our primary uses of capital have been for the exploration, development and acquisition of oil and natural gas properties.

Cash Flows

Our cash flows for the three months ended March 31, 2019 and 2018 are presented below:
 Three Months Ended
March 31,
 2019 2018
 (in thousands)
Net cash provided by (used in) operating activities$63,615
 $(8,774)
Net cash used in investing activities(158,200) (111,254)
Net cash provided by financing activities89,891
 121,300
Net (decrease) increase in cash and cash equivalents$(4,694) $1,272

Cash flows provided by operating activities. Cash flows provided by operating activities for the three months ended March 31, 2019 were $63.6 million compared to cash flows used in operating activities of $8.8 million for the three months ended March 31, 2018. The cash flows provided by operating activities in 2019 is primarily driven by changes in working capital accounts and increased revenues partially offset by higher cash expenses due to higher activity levels in 2019.

Cash flows used in investing activities. Cash flows used in investing activities for the three months ended March 31, 2019 were $158.2 million compared to $111.3 million for the three months ended March 31, 2018. 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 2019 compared to the same period in 2018.

Cash flows provided by financing activities. Cash flows provided by financing activities for the three months ended March 31, 2019 were $89.9 million compared to $121.3 million for the three months ended March 31, 2018. Cash flows provided by financing activities for both periods are attributable to borrowings from our Credit Facility. Borrowings from our Credit Facility decreased in the three months ended March 31, 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.

Credit Facility

Our Credit Facility is a $750.0 million credit agreement with a maturity date of September 5, 2022. As of March 31, 2019, the borrowing base is set at $750.0 million. Redetermination of the borrowing base occurs semiannually on or about October 1 and April 1. As of March 31, 2019, we had $602.6 million of outstanding borrowings and no letters of credit outstanding under the Credit Facility. We have and are continuing to evaluate financing options that would enhance our liquidity.

Amounts borrowed under the Credit Facility bear interest at LIBOR or the ABR at our 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

33


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 and 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.

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; (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.

The Credit Facility also contains financial covenants requiring us to comply with a leverage ratio of 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 consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash assets and liabilities under ASC Topic 815 Derivatives and Hedging and ASC Topic 410 Asset Retirement and Environmental Obligations) as of the fiscal quarter ended of not less than 1.00 to 1.00.

As of March 31, 2019, we were in compliance with the covenants under the Credit Facility.

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. To date, funding for these cash needs has been provided by internally-generated cash flow and financing under our Credit Facility.

Our capital budget for 2019 is $520 million to $570 million. During the three months ended March 31, 2019, drilling and completion capital expenditures were $161.6 million. We expect our 2019 capital budget 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. Capital expenditures for our operated properties are 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, prevailing and anticipated prices for oil and natural gas, the 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 response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for the remainder of 2019, we believe our cash flow from operations, cash on hand, borrowings under our Credit Facility and access to capital markets will be sufficient to fund our operations for the next 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.

34



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.

Off-Balance Sheet Arrangements

We enter into certain off-balance sheet arrangements and transactions, including operating lease arrangements and undrawn 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.

Contractual Obligations

Our contractual obligations include long-term debt, cash interest expense on debt, pipe and equipment purchase commitments, office building leases, and drilling rig commitments. 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%. There have been no other material changes in our contractual commitments and obligations from amounts listed under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Contractual Obligations” in our Annual Report on Form 10‑K.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based on the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors that are believed to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Although management believes they are reasonable, actual results could differ from these estimates and assumptions.


35


Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a number of market risks including commodity price risk, credit risk and interest rate risk. The following information provides quantitative and qualitative information about our potential risks and how we seek to manage such risks.

Commodity Price Risk

The following table reflects our open commodity contracts as of 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 prices swaps     
Volume (Bbl)825,000
 
 825,000
Weighted-average price$32.25
 $
 $32.25

Our primary market risk exposure is in the price we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our oil and natural gas production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows. These derivatives are not designated as a hedging instrument for hedge accounting under GAAP and as such, gains or losses resulting from the change in fair value along with the gains or losses resulting from settlement of derivative contracts are reflected as gain or loss on derivative contracts included in the consolidated statements of operations.

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.




36



At March 31, 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 our 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 NGL 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 oil, natural gas and NGL receivables with two significant purchasers. We do not believe the loss of any single purchaser would materially impact our 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 the over-the-counter market. The entry into derivative transactions in the over-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 our 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 liabilities 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 ABR, in each case adjusted upward by an applicable margin based on the utilization percentage of the Credit Facility.

As of March 31, 2019, we had $602.6 million in outstanding borrowings under our Credit Facility. At March 31, 2019, the weighted average interest rate on borrowings under our Credit Facility was 5.25%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $6.0 million based on outstanding borrowings of $602.6 million under our Credit Facility as of March 31, 2019.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. 

As required by Rule 13a-15 and 15d-15 of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined

37


in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at March 31, 2019 because of the material weaknesses in our internal control over financial reporting as further described below.

Identification of Material Weaknesses

As described in Item 9A of our 2018 Form 10-K, 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 control 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 our period-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 at period-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 of IT-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

38



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.
(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 relevant 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.

Remediation Plan for the Material Weaknesses

We have taken and will continue to take a number of actions to remediate these material weaknesses. We have implemented measures designed to improve our internal control over financial reporting and remediate the control deficiencies that led to the material weaknesses. We have hired additional IT and accounting personnel with appropriate technical skillsets and initiated design and implementation of our control 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 these 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 internal control over financial reporting will not be identified in the future.

Changes in Internal Control over Financial Reporting. 

Except as described herein, there were no changes in our internal control over financial reporting during the quarter ended March 31, 2019, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION
Item 1. Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business, including, but not limited to, commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. We cannot 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 material adverse impact on our financial condition.

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.


39



Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Annual Report on Form 10-K, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in the Annual Report on Form 10-K, except as set forth below.

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.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosure

Not applicable.

Item 5. Other Information

Not applicable.


40




Item 6. Exhibits
Exhibit No. Exhibit
 Linn 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 Form 8-K filed on September 24, 2018)
 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 8-K filed on September 24, 2018)
 Master Reorganization Agreement, dated September 17, 2018, by and among Linn Energy, Inc., Roan Holdings, LLC, and Roan Resources LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on September 21, 2018)
 Separation and Distribution Agreement, dated August 7, 2018, by and between Linn Energy, Inc. and Riviera Resources, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on August 10, 2018)
 Agreement and Plan of Merger, dated July 25, 2018, by and among Linn Energy Inc., New LINN Inc. and Linn Merger Sub #1, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on July 26, 2018)
 Second Amended and Restated Certificate of Incorporation of Roan Resources, Inc. (incorporated by reference to Exhibit 3.1 to Form 8-K filed on September 27, 2018)
 Second Amended and Restated Bylaws of Roan Resources, Inc. (incorporated by reference to Exhibit 3.2 to Form 8-K filed on September 27, 2018)
 Registration Rights 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 8-K filed on September 24, 2018)
 Stockholders 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 4.2 to Form 8-K filed on September 24, 2018)
 Amendment 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)
 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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 Label Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
   
*Filed herewith
** Furnished herewith
 Compensatory plan or arrangement


41



SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ROAN RESOURCES, INC.

   
   
Date:May 15, 2019/s/ Joseph A. Mills
  Joseph A. Mills
  Executive Chairman
  (Principal Executive Officer)
   
   
   
Date:May 15, 2019/s/ David M. Edwards
  David M. Edwards
  Chief Financial Officer
  (Principal Financial Officer)
   
   
   




42