UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
þ☑Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 20162019
or
o☐Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission file number 001-31539
SM ENERGY COMPANYCOMPANY
(Exact name of registrant as specified in its charter)
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Delaware | | 41-0518430 | |
| (State or other jurisdiction of incorporation or organization) | 41-0518430
| (I.R.S. Employer Identification No.) | |
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| 1775 Sherman Street, Suite 1200, | Denver, | Colorado | | 80203 | |
| (Address of principal executive offices) | 80203
| (Zip Code) | |
(303) (303)861-8140
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| Common stock, $.01 par value | SM | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yesþ☑ No o☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o☐Noþ☑
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 preceding 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. Yesþ ☑Noo☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesþ ☑Noo☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
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| Large accelerated filerþ | ☑ | | Accelerated filero | ☐ | |
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| Non-accelerated filer | ☐ | | Smaller reporting company | ☐ | |
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| | | | Emerging growth company | ☐ | |
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Non-accelerated filer o (DoIf an emerging growth company, indicate by check mark if the registrant has elected not check if a smaller reporting company)
| Smaller reporting company oto 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. ☐
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o☐ No þ☑
The aggregate market value of the 67,398,312111,242,033 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on June 30, 2016,28, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, of $27.00$12.52 per share, as reported on the New York Stock Exchange, was $1,819,754,424.$1,392,750,253. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
As of February 15, 2017,6, 2020, the registrant had 111,257,703112,988,364 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 20172020 annual meeting of stockholders to be filed within 120 days after December 31, 2016.2019.
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| TABLE OF CONTENTS |
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| TABLE OF CONTENTS |
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Cautionary Information about Forward-Looking Statements
This Annual Report on Form 10-K (“Form 10-K”) contains “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 facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “intend,” “pending,” “plan,” “potential,” “project,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:
the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”);
our outlook on future crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this document) prices, well costs, service costs, lease operating costs, and general and administrative costs;
the drilling of wells and other exploration and development activities, the ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;
possible or expected acquisitions and divestitures, including the possible divestiture or farm-down of, or joint venture relating to, certain properties;
oil, gas, and NGL reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;
future oil, gas, and NGL production estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;
cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;
plans, objectives, expectations and intentions; and
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| • | other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report. |
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in Part I, Item 1A, Risk Factors - Risks Related to Our Business below and elsewhere in this report. The forward-looking statements in this report speak as of the filing of this report. Although, we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.
Glossary of Oil and Gas Terms
The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the Securities and Exchange Commission’s (“SEC”) website at www.sec.gov.
Ad valorem tax. A tax based on the value of real estate or personal property.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs, water, or other liquid hydrocarbons.
BBtu. One billion British thermal units.
Bcf.One billion cubic feet, used in reference to gas.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas to one Bbl of oil or NGLs.
Btu. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Developed acreage.The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (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.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil, gas, and/or NGLs in commercial quantities.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and gas) rights.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.
Lease operating expenses. The expenses incurred in the lifting of oil, gas, and/or NGLs from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.
MBbl. One thousand barrels of oil, NGLs, water, or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet, used in reference to gas.
MMBbl. One million barrels of oil, NGLs, water, or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet, used in reference to gas.
Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.
NGLs.The combination of ethane, propane, isobutane, normal butane, and natural gasoline that when removed from gas become liquid under various levels of higher pressure and lower temperature.
NYMEX WTI. New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for oil.
NYMEX Henry Hub. New York Mercantile Exchange Henry Hub, a common industry benchmark price for gas.
OPIS. Oil Price Information Service, a common industry benchmark for NGL pricing at Mont Belvieu, Texas.
PV-10 (Non-GAAP). PV-10 is a non-GAAP measure. The present value of estimated future revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.
Productive well. A well that is producing oil, gas, and/or NGLs or that is capable of commercial production of those products.
Proved reserves. Those quantities of oil, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Recompletion. The completion of an existing wellbore in a formation other than that in which the well has previously been completed.
Reserve life index. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil, gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resource play. A term used to describe an accumulation of oil, gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has lower expected geological risk.
Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from oil, gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.
Royalty interest. An interest in an oil and gas property entitling the owner to shares of oil, gas, and NGL production free of costs of exploration, development, and production operations.
Seismic. Thesending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
Standardized measure of discounted future net cash flows. The discounted future net cash flows related to estimated proved reserves based on prices used in estimating the reserves, year end costs, and statutory tax rates, at a 10 percent annual discount rate. The information for this calculation is included in Supplemental Oil and Gas Information (unaudited) located in Part II, Item 8 of this report.
Track record. Current year conversions of proved undeveloped reserves to proved developed reserves, divided by beginning of the year proved undeveloped reserves.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and NGLs regardless of whether such acreage contains estimated net proved reserves.
Undeveloped reserves. 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. The applicable SEC definition of undeveloped reserves provides that 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.
Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs.
PART I
When we use the terms “SM Energy,” “the Company,the “Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under in the Glossary of Oil and Gas Terms.Terms section of this report. Throughout this document we make statements and projections that address future expectations, possibilities, or events, all of which may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this documentreport for an explanation of these types of statements.statements and the associated risks and uncertainties.
ITEMS 1. andAND 2. BUSINESS andAND PROPERTIES
General
We are an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughoutNGLs in the document) in onshore North America. We werestate of Texas. SM Energy was founded in 1908, and incorporated in Delaware in 1915. Our1915, and our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”
Our principal offices areoffice is located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Strategy
Our strategic objectiveAt SM Energy, our purpose is to profitably build our ownershipmake people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and operatorship of North American oil, gas,prosperity, and NGL producing assets that have high operating marginshaving a positive impact in the communities where we live and significant opportunitieswork. Our long-term vision for additional economic investment. We pursue growth opportunities through both acquisitions and exploration, and seekthe Company is to maximize thesustainably grow value for all of our assets through industry-leading technology applicationstakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top tier assets. Our current energy project development portfolio is focused on oil and outstanding operational execution. We focus on achieving high full-cycle economic returns on our investments and maintaining a simple, strong balance sheet.
gas producing properties in the state of Texas.
Significant Developments in 20162019
Acquisition Activity. Strategic Transformation. During 2019, we completed our strategic transformation, which commenced in 2016 we acquired approximately 62,000 net acres in the Midland Basin in Howardthrough a series of asset acquisitions and Martin Counties, Texas with producing and prospective intervals in the Lower and Middle Spraberry and Wolfcamp A and B shale formations and 15.0 MMBOE of existing proved reserves. We acquired these properties for total consideration of approximately $2.6 billion, which included $2.2 billion in cash and the issuance of 13.4 million shares of our common stock.
Divestiture Activity. During 2016, we divested a total of 47.7 MMBOE of proved reserves in multiple transactions for total net cash proceeds of approximately $946.1 million. Our most significant divestiture was the sale of our Williston Basin assets outside of Divide County, North Dakota (referred to as “Raven/Bear Den” throughout this report) indivestitures. For the fourth quarter of 2016.
2019, we passed an important milestone by achieving a positive difference between our net cash provided by operating activities and our net cash used in investing activities. Our operational execution in 2019 was outstanding, achieving our objectives in important industry metrics, including key top-quartile benchmarks for environmental, health, and safety performance. We were also successful in proving up additional investment opportunities on our existing acreage positions.Production. Our average daily production in 2019 consisted of 59.9 MBbl of oil, 300.8 MMcf of gas, and 22.2 MBbl of NGLs, for an average net daily equivalent production rate of 132.3 MBOE, which represented a 10 percent increase compared with 2018. This increase was primarily driven by a 25 percent increase in production volumes from our Midland Basin assets as a result of strong well performance, increased drilling and completion efficiencies, improved completion designs, and longer laterals. We completed more lateral feet in 2019 compared with 2018, driving continued increases in volumes at a lower average drilling and completion cost. On a retained asset basis, our production volumes increased 13 percent in 2019. As a result of the above, oil production revenue was approximately 75 percent of total production revenue for the year ended December 31, 2019, compared with 65 percent and 52 percent for the years ended December 31, 2018 and 2017, respectively. Please refer to Areas of Operationbelow for additional discussion.
Reserves and Capital Investment. Our estimated proved reserves decreased 16eight percent to 395.8462.0 MMBOE at December 31, 2016,2019, from 471.3503.4 MMBOE at December 31, 2015, of which 47.72018. Reserve additions from discoveries, extensions, and infills totaled 98.4 MMBOE related to the divestiture of proved reserves, as discussed above. We had strong reserve additions of 108.2 MMBOE asand were a result of our successsuccessful development programs, completion optimizations that resulted in reducing costs, optimizingimproved well performance, and enhancing completions, and generating better well results. These successesdevelopment plan improvements that we believe will enhance inventory value. The 2019 reserve additions were offset by negative reserve2019 production volumes of 48.3 MMBOE and by downward revisions due toof 94.7 MMBOE, which resulted primarily from the impact of lower commodity prices and the removalprices. Our proved reserve life index decreased to 9.6 years as of certain longer term proved undeveloped reserves that reflects our shift to develop our predominately unproven Midland Basin properties.December 31, 2019, compared with 11.5 years as of December 31, 2018. Costs incurred for development and exploration activities, excluding acquisitions, decreased 4823 percent from the prior year to $713.6 million$1.0 billion in 2016 when compared with 2015. Our proved reserve life index decreased slightly to 7.2 years in 2016.2019. Please refer to Reserves Areas of Operationand Core Operational AreasReservesbelow, and to Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report for additional discussion.
Liquidity. During 2016, we issued $500.0Net Cash Provided by Operating Activities. Net cash provided by operating activities was $823.6 million in aggregate principal amount of 6.75% Senior Notes due September 15, 2026, at par, for net proceeds of $491.6 million. Additionally, we issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021, for net proceeds of $166.6 million. During 2016, we also repurchased a total of $46.3 million in aggregate principal amount of a portion of our Senior Notes in open market transactions and paid down the entire $202.0 million outstanding balance on our
credit facility as ofyear ended December 31, 2015. Further, our borrowing base and lender commitments were reduced to $1.17 billion as of2019, compared with $720.6 million for the year ended December 31, 2016.2018, which was an increase of 14 percent year-over-year. Oil, gas, and NGL production revenues decreased for the year ended December 31, 2019, compared with 2018, as the impact from higher production volumes was offset by lower commodity prices. However, the impact of lower commodity prices in 2019 was offset by a net derivative cash settlement gain of $39.2 million for the year ended December 31, 2019, compared to a net derivative cash settlement loss of $135.8 million for 2018. Please refer to Analysis of Cash Flow Changes Between 2019 and 2018 and Between
2018 and 2017 in Overview of Liquidity and Capital Resourcesin Part II, Item 7, and to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Outlook
Our business outlook for the next several years is a continuation of our trajectory of improving operating margins and cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics. Our total capital program in 2020, is budgeted to be between $825.0 million and $850.0 million, and is expected to be approximately 20% lower compared with 2019, in large part due to significant cost reductions and efficiencies that were achieved in 2019. Our 2020 program will be focused on highly economic oil development projects in both our Midland Basin and South Texas assets. We expect total production volumes in 2020 to decrease slightly compared with 2019 as expected continued growth in our oil production volumes will not completely offset expected decreases in gas and NGL production volumes.
Sustainability is a key focus of our plans, in terms of positioning ourselves financially to participate in future energy investment opportunities, and executing our strategy of being a premier operator with high standards for corporate responsibility. We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive difference in the communities where we live and work; and transparency in reporting on our progress in these areas.
Please refer to Overview of Liquidity and Capital Resources in Part II, Item 7 of this report for additional discussion onof how we expect to fund our current and future liquidity.
Equity Market Activities. During 2016, we issued approximately 29.3 million shares of our common stock in two public equity offerings and received $934.1 million in net proceeds. These issuances were in addition to the approximate 13.4 million shares of our common stock issued as partial consideration for certain acquired properties as discussed above.
Production. Our average daily production in 2016 consisted of 45.4 MBbl of oil, 401.5 MMcf of gas, and 38.8 MBbl of NGLs, for an average equivalent production rate of 151.0 MBOE per day, which represents a 14 percent decrease on an equivalent basis compared with 2015. This decrease in production was driven by our reduced drilling and completion activity and divestiture of assets. Please refer to Core Operational Areas below for additional discussion.
Impairments. We recorded impairments of proved and unproved properties totaling $435.0 million for the year ended December 31, 2016. These impairments were largely due to the continued decline in commodity prices in early 2016 impacting our outside-operated Eagle Ford shale assets and negative performance revisions on our Powder River Basin assets at year-end 2016.
2020 capital program.Outlook for 2017Areas of Operation
Our priorities for 2017 are to:
demonstrate the value of our 2016 acquisitions in the Midland Basin;
generate high margin production growth from our operated acreage positions2019 operations were concentrated in the Midland Basin and Eagle Ford shale;
successfully execute the sale of our outside-operated Eagle Ford shale and Divide County assets; and
reduce our outstanding debt.
Our capital program for 2017, excluding acquisitions, is expected to be approximately $875 million with the focus on our core operated acreage positions in the Midland Basin and Eagle Ford shale. We plan to continue our focus on conducting safe operations evenSouth Texas, as we ramp up activity. Please refer to Outlook for 2017 under Part II, Item 7 of this report for additional discussion concerning our capital plans for 2017.
Core Operational Areas
Our 2016 operations were concentrated in three onshore operating areas in the United States.further described below. The following table summarizes estimated proved reserves, production, and costs incurred in oil and gas producing activities (“costs incurred”) for the year ended December 31, 2016,2019, for our core operatingthese areas:
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| South Texas & Gulf Coast | | Permian | | Rocky Mountain | | Total (1) | Midland Basin | | South Texas | | Total (1) |
| Proved Reserves | | | | | | | | |
| Proved reserves | | | | | | |
| Oil (MMBbl) | 35.4 |
| | 37.9 |
| | 31.6 |
| | 104.9 |
| 167.5 |
| | 16.6 |
| | 184.1 |
|
| Gas (Bcf) | 989.3 |
| | 94.6 |
| | 27.2 |
| | 1,111.1 |
| 398.8 |
| | 824.4 |
| | 1,223.2 |
|
| NGLs (MMBbl) | 105.2 |
| | 0.1 |
| | 0.5 |
| | 105.7 |
| 0.1 |
| | 73.9 |
| | 74.0 |
|
MMBOE (2)(1) | 305.4 |
| | 53.8 |
| | 36.5 |
| | 395.8 |
| 234.1 |
| | 227.8 |
| | 462.0 |
|
| Relative percentage | 77 | % | | 14 | % | | 9 | % | | 100 | % | 51 | % | | 49 | % | | 100 | % |
| Proved Developed % | 55 | % | | 40 | % | | 53 | % | | 53 | % | |
| Proved developed % | | 49 | % | | 58 | % | | 53 | % |
| Production | | | | | | | | | | | | |
| Oil (MMBbl) | 5.5 |
| | 2.7 |
| | 8.3 |
| | 16.6 |
| 20.5 |
| | 1.3 |
| | 21.9 |
|
| Gas (Bcf) | 130.9 |
| | 6.0 |
| | 10.0 |
| | 146.9 |
| 34.4 |
| | 75.4 |
| | 109.8 |
|
| NGLs (MMBbl) | 13.9 |
| | — |
| | 0.3 |
| | 14.2 |
| — |
| | 8.1 |
| | 8.1 |
|
MMBOE (2)(1) | 41.2 |
| | 3.8 |
| | 10.3 |
| | 55.3 |
| 26.3 |
| | 22.0 |
| | 48.3 |
|
Avg. Daily Equivalents (MBOE/d) (1) | 112.6 |
| | 10.2 |
| | 28.2 |
| | 151.0 |
| |
Avg. daily equivalents (MBOE/d) (1) | | 72.0 |
| | 60.3 |
| | 132.3 |
|
| Relative percentage | 74 | % | | 7 | % | | 19 | % | | 100 | % | 54 | % | | 46 | % | | 100 | % |
Costs Incurred (in millions)(3) | $ | 254.6 |
| | $ | 2,874.1 |
| | $ | 226.0 |
| | $ | 3,373.9 |
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Costs incurred (in millions) (2) (3) | | $ | 859.6 |
| | $ | 160.9 |
| | $ | 1,040.2 |
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(1) | TotalsAmounts may not sum or calculate due to rounding. |
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(2) | As of December 31, 2016, our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 74.0 MMBOE of our proved reserves as of December 31, 2016, and approximately 9.7 MMBOE of 2016 production on an equivalent basis. Additionally, subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets. |
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(3)
| AmountsRegional costs incurred do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activityactivities that isare excluded from thethis regional table above.table. Please refer to the caption Costs Incurred in Oil and Gas Producing Activities in the Supplemental Oil and Gas Information section (unaudited)in Part II, Item 8 of this report.
|
| |
(3) | Costs incurred for 2019 included $11.3 million related to acquisitions of primarily unproved oil and gas properties in the Midland Basin. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report. |
Outside ofExcluding acquisition activity, costs incurred decreased in 2019 by 23 percent compared with 2018 primarily due to increased operational efficiencies and decreased drilling, completion crew, and sand costs incurred in developing our Permian region, we reduced our capital spending activity in 2016 in light of the low commodity price environment. We had strong proved reserve additions as a result of our success in reducing costs, optimizing and enhancing completions, and generating better well results in our core development programs. However, totalMidland Basin assets. Total estimated proved reserves at year end 2019 decreased eight percent from year-end 2015 due2018. Production increased 10 percent on an equivalent basis for the year ended December 31, 2019, compared with 2018, and increased 13 percent on a retained assets basis.
Midland Basin. Our Midland Basin assets are located within the Permian Basin in Western Texas and are comprised of approximately 80,000 net acres (“Midland Basin”). In 2019, we focused on continuing to divestitures, a negativedelineate, develop, and expand our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
In 2019, we incurred $859.6 million of costs and averaged six drilling rigs and three completion crews. The majority of our Midland Basin capital was deployed on projects targeting the Lower Spraberry and Wolfcamp A and B intervals on our RockStar assets in Howard and Martin Counties, Texas and Sweetie Peck assets in Upton and Midland Counties, Texas. We completed 123 gross (111 net) wells and full-year production increased 25 percent year-over-year to 26.3 MMBOE for 2019. As of December 31, 2019, there were 51 gross (48 net) wells that had been drilled but not completed in our Midland Basin program. Estimated proved reserves increased nine percent to 234.1 MMBOE at year end 2019, from 214.3 MMBOE at year end 2018. This increase was driven by additions of 58.9 MMBOE from discoveries, extensions and infill, and acquisitions, partially offset by 12.6 MMBOE of downward revisions from price, revision,performance, and removal ofaged proved undeveloped reserves as a result of changes in our development plan.reserves.
South Texas. Our South Texas & Gulf Coast Region. Operationsassets are comprised of approximately 158,900 net acres located in ourDimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas & Gulf Coast region are managed from our office in Houston, Texas. Within this region, we have both an operated and outside-operatedfocused on developing the Eagle Ford shale program.formation and delineating the Austin Chalk formation. Our operatedoverlapping acreage position in the Eagle Ford shale position includes approximately 161,000 net acres and accounted for approximately 75 percent of our total Eagle Ford shale production in 2016. Our outside-operated Eagle Ford shale program includes approximately 36,000 net acres. Our acreage positionAustin Chalk formations covers a significant portion of the western Eagle Ford shale play, includingand Maverick Basin Austin Chalk (“Eagle Ford shale”) and includes acreage inacross the oil/condensate, NGL-rich gas,oil, gas-condensate, and dry gas windows of the play. Our outside-operated Eagle Ford shale assets, including the associated midstream assets, were heldwith gas composition amenable to processing for sale as of December 31, 2016, with the sale expected to close in the first quarter of 2017.
NGL extraction.
In 2016,2019, we focused our capital on completing wells that were drilled but not completed at year-end 2015 and drilling wells required to satisfy lease obligations. We incurred $253.6$160.9 million of costs to add approximately 66.7 MMBOE of estimated proved reserves through ourand averaged one drilling activities. Overall, estimated proved reserves decreased 11 percent to 305.4 MMBOE at Decemberrig and one completion crew. We completed 31 2016, from 342.4 MMBOE at year-end 2015. Production decreased 15gross (20 net) wells during 2019, and full-year regional production increased one percent year-over-year to 41.222.0 MMBOE for 2016 due to reduced drilling activity during the year.2019. As of December 31, 2016, we had 472019, there were 21 gross and net(21 net) wells that had been drilled but not completed in our operatedSouth Texas program.
Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to our joint development agreement. The agreement provided that the third party carried substantially all drilling and completion costs and receives a majority of the working and revenue interest in these wells until certain payout thresholds are reached. This arrangement allowed us to leverage third-party capital to prove up the value of our Eagle Ford shale program.
Permian Region. Operations in our Permian region are managed from our office in Midland, Texas. In 2016, we closed multiple transactionsNorth area, while also allowing us to test cutting edge technology, capture additional technical data, satisfy certain lease obligations, and potentially expand economic drilling inventory in the Midland Basin in west Texas acquiring approximately 62,000 net acresfuture. All wells subject to this agreement were drilled and 15.0 MMBOEcompleted as of existing proved reserves in Howard and Martin Counties (referred to as our “RockStar” program throughout this report).
The table above reflects costs incurred on acquisitions totaling $2.6 billion, including $2.2 billion in cash consideration and the issuance of approximately 13.4 million shares of our common stock valued at $437.2 million. Additionally, for the year ended December 31, 2016,2019.
During 2019, we incurred $216.7 million of costs to add approximately 24.0added 43.0 MMBOE of estimated proved reserves, through our drilling activities. The majorityoffset by downward revisions of this capital was deployed on our Sweetie Peck assets in Upton County, Texas, where we ran two drilling rigs throughout 2016. We added two drilling rigs on our acquired RockStar acreage in the fourth quarter82.1 MMBOE, of 2016,which 68.5 MMBOE resulted from decreased commodity pricing and expect to add two additional rigs on this acreage in early 2017 with the focus on delineating and developing the acreage. Estimated proved reserves increased 159 percent to 53.810.3 MMBOE at year-end 2016resulted from 20.8 MMBOE at year-end 2015. Production increased 40 percent year-over-year to 3.8 MMBOE for 2016.performance revisions. As of December 31, 2016, we had 17 gross and net wells that had been drilled but not completed in our operated Midland Basin program.
Rocky Mountain Region. Operations in our Rocky Mountain region were managed from our office in Billings, Montana until November 2016, at which time we closed that office and began managing our Rocky Mountain regional operations from our corporate office in Denver, Colorado. As of December 31, 2016, we had approximately 124,000 net acres in Divide County, North Dakota, and approximately 156,000 net acres in the Powder River Basin.
In 2016, we incurred $223.9 million of costs to add approximately 17.4 MMBOE ofa result, estimated proved reserves in our Rocky Mountain region through our drilling activities. Estimated proved reserves decreased 21 percent to 36.5227.8 MMBOE at year-end 2016year end 2019, from 108.1289.1 MMBOE at year-end 2015, primarily due to the divestiture of our Raven/Bear Den assets and other non-core Rocky Mountain region assets. Production decreased nine percent year-over-year to 10.3 MMBOE for 2016. Current activities in our Powder River Basin program are under an acquisition and development funding agreement with a third party in which our costs to drill and complete a specified number of initial wells are being carried by such party. As of December 31, 2016, we had 20 gross (17 net) drilled but not completed wells in our operated Bakken/Three Forks program. Subsequent to December 31, 2016, we announced our plans to sell our remaining Williston Basin assets in Divide County, North Dakota by mid-2017.year end 2018.
Reserves
The table below presents summary information with respect to the estimates of our proved reserves for each of the years in the three-year period ended December 31, 2016. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit at least 80 percent of our total calculated proved reserve PV-10 for each year presented. The prices used in the calculation of proved reserve estimates reflect the 12-month average of the first-day-of-the-month prices in accordance with Securities and Exchange Commission (“SEC”) rules, and were $42.75 per Bbl for oil, $2.47 per MMBtu for natural gas, and $19.50 per Bbl for NGLs for the year ended December 31, 2016. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves.
Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. PV-10 shown in theThe following table presents the standardized measure of discounted future net cash flows and pre-tax PV-10 (“PV-10”). PV-10 is a non-GAAP financial measure, and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor the standardized measure of discounted future net cash flows nor PV-10 represents the fair market value of our oil and gas properties. We and others in the oil and gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held without regard to the specific tax characteristics of such entities. Please refer to the Glossary of Oil and Gas Terms section of this report for additional information regarding these measures.measures and refer to the reconciliation of the standardized measure of discounted future net cash flows to PV-10 set forth below. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – Risks Related to Our Businessbelow.
Our ability to replace our production with new oil and gas reserves is critical to us.the future success of our business. Please refer to the reserve replacementlife index term in the Glossary of Oil and Gas Terms section of this report for information describing how this metric is calculated.
The following table summarizes estimated proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP), the prices used in the calculation of proved reserves estimates, and PV-10reserve life index as of December 31, 2016, 2015,2019, 2018, and 2014:2017:
| | | | As of December 31, | As of December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Reserve data: | | | | | | | | | | |
| Proved developed | | | | | | | | | | |
| Oil (MMBbl) | 48.5 |
| | 75.6 |
| | 89.3 |
| 85.0 |
| | 68.2 |
| | 58.6 |
|
| Gas (Bcf) | 609.1 |
| | 644.4 |
| | 784.6 |
| 712.1 |
| | 699.1 |
| | 642.9 |
|
| NGLs (MMBbl) | 58.6 |
| | 61.5 |
| | 66.7 |
| 43.4 |
| | 60.1 |
| | 49.0 |
|
MMBOE (1) | 208.7 |
| | 244.5 |
| | 286.8 |
| 247.0 |
| | 244.8 |
| | 214.7 |
|
| Proved undeveloped | | | | | | | | | | |
| Oil (MMBbl) | 56.4 |
| | 69.6 |
| | 80.4 |
| 99.1 |
| | 107.6 |
| | 99.6 |
|
| Gas (Bcf) | 502.0 |
| | 619.7 |
| | 682.0 |
| 511.1 |
| | 622.7 |
| | 637.2 |
|
| NGLs (MMBbl) | 47.1 |
| | 53.9 |
| | 66.8 |
| 30.6 |
| | 47.2 |
| | 47.6 |
|
MMBOE (1) | 187.1 |
| | 226.8 |
| | 260.9 |
| 214.9 |
| | 258.6 |
| | 253.4 |
|
Total proved (1) | | | | | | | | | | |
| Oil (MMBbl) | 104.9 |
| | 145.3 |
| | 169.7 |
| 184.1 |
| | 175.7 |
| | 158.2 |
|
Gas (Bcf) (2) | 1,111.1 |
| | 1,264.0 |
| | 1,466.5 |
| 1,223.2 |
| | 1,321.8 |
| | 1,280.1 |
|
| NGLs (MMBbl) | 105.7 |
| | 115.4 |
| | 133.5 |
| 74.0 |
| | 107.4 |
| | 96.5 |
|
MMBOE (3) | 395.8 |
| | 471.3 |
| | 547.7 |
| 462.0 |
| | 503.4 |
| | 468.1 |
|
| Proved developed reserves % | 53 | % | | 52 | % | | 52 | % | 53 | % | | 49 | % | | 46 | % |
| Proved undeveloped reserves % | 47 | % | | 48 | % | | 48 | % | 47 | % | | 51 | % | | 54 | % |
| | | | | | | | | | | |
| Reserve data (in millions): | | | | | | | | | | |
| Standardized measure of discounted future net cash flows (GAAP) | $ | 1,152.1 |
| | $ | 1,790.5 |
| | $ | 5,698.8 |
| $ | 4,104.0 |
| | $ | 4,654.4 |
| | $ | 3,024.1 |
|
| PV-10 (non-GAAP): | | | | | | | | | | |
| Proved developed PV-10 | $ | 1,051.1 |
| | $ | 1,593.0 |
| | $ | 5,253.0 |
| $ | 2,830.4 |
| | $ | 3,084.2 |
| | $ | 1,984.2 |
|
| Proved undeveloped PV-10 | 101.0 |
| | 197.5 |
| | 2,363.9 |
| 1,532.4 |
| | 2,020.1 |
| | 1,072.3 |
|
| Total proved PV-10 | $ | 1,152.1 |
| | $ | 1,790.5 |
| | $ | 7,616.9 |
| |
| Total proved PV-10 (non-GAAP) | | $ | 4,362.8 |
| | $ | 5,104.3 |
| | $ | 3,056.5 |
|
| | | | | | | |
12-month trailing average prices (3) | | | | | | |
| Oil (per Bbl) | | $ | 55.69 |
| | $ | 65.56 |
| | $ | 51.34 |
|
| Gas (per MMBtu) | | $ | 2.58 |
| | $ | 3.10 |
| | $ | 3.00 |
|
| NGLs (per Bbl) | | $ | 22.68 |
| | $ | 33.45 |
| | $ | 27.69 |
|
| | | | | | | | | | | |
| Reserve life index (years) | 7.2 |
| | 7.3 |
| | 9.9 |
| 9.6 |
| | 11.5 |
| | 10.5 |
|
| |
(1) | TotalsAmounts may not sum or calculate due to rounding. |
| |
(2) | For the years ended December 31, 2016,2019, 2018, and 2015,2017, proved gas reserves contained 43.744.9 Bcf, 59.1 Bcf, and 48.1 Bcf of gas, respectively, that we expect to produce and use as a field equipment fuel source (primarily forto power compressors). |
| |
(3) | As of December 31, 2016, our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing dateThe prices used in the first quartercalculation of 2017. These assets represented approximately 74.0 MMBOEproved reserve estimates reflect the 12-month average of the first-day-of-the-month prices in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our estimated proved reserves as of December 31, 2016. Additionally, subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets.reserves. |
The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the pre-tax PV-10 (Non-GAAP)(non-GAAP) of total estimated proved reserves. Please see refer to the Glossary of Oil and Gas Termssection of this report forthe definitions of standardized measure of discounted future net cash flows and PV-10 in the Glossary of Oil and Gas Terms section of this report.PV-10.
| | | | As of December 31, | As of December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| | (in millions) | (in millions) |
| Standardized measure of discounted future net cash flows (GAAP) | $ | 1,152.1 |
| | $ | 1,790.5 |
| | $ | 5,698.8 |
| $ | 4,104.0 |
| | $ | 4,654.4 |
| | $ | 3,024.1 |
|
| Add: 10 percent annual discount, net of income taxes | 937.1 |
| | 1,307.1 |
| | 3,407.2 |
| 2,955.3 |
| | 3,847.1 |
| | 2,573.2 |
|
| Add: future undiscounted income taxes | — |
| | — |
| | 3,511.4 |
| 579.8 |
| | 1,012.2 |
| | 205.7 |
|
| Undiscounted future net cash flows | 2,089.2 |
| | 3,097.6 |
| | 12,617.4 |
| |
| Pre-tax undiscounted future net cash flows | | 7,639.1 |
| | 9,513.7 |
| | 5,803.0 |
|
| Less: 10 percent annual discount without tax effect | (937.1 | ) | | (1,307.1 | ) | | (5,000.5 | ) | (3,276.3 | ) | | (4,409.4 | ) | | (2,746.5 | ) |
| PV-10 (non-GAAP) | $ | 1,152.1 |
| | $ | 1,790.5 |
| | $ | 7,616.9 |
| $ | 4,362.8 |
| | $ | 5,104.3 |
| | $ | 3,056.5 |
|
Proved Undeveloped Reserves
Proved undeveloped reserves include those reserves that are expected to be recovered from newfuture wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.time. As of December 31, 2016,2019, we did not have any proved undeveloped reserves that had been on our books in excess of five years.years, and none of our proved undeveloped reserves were on acreage expected to expire or on acreage that was not expected to be held through renewal before the targeted completion date.
For proved undeveloped locations that are more than one location removeddevelopment spacing area from developed producing locations, we utilized reliable geologic and engineering technology to addwhen booking estimated proved undeveloped reserves. Of the 214.9 MMBOE of total proved undeveloped reserves as of December 31, 2019, approximately 44.460.1 MMBOE of proved undeveloped reserves in the more developed portions of our Eagle Ford shale position, 8.3Midland Basin and 68.7 MMBOE of proved undeveloped reserves in our South Texas position were offset by more than one development spacing area from the morenearest developed portion of our Wolfcamp and Lower Spraberry shale positions in the Midland Basin, and 0.9 MMBOE of proved undeveloped reserves in the more developed portions of our Bakken/Three Forks shale position.producing location. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected) and petrophysical analysis of that log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as significant statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to immediate offsetsdevelopment spacing areas that are immediately adjacent to producing wells.
developed spacing areas.
As of December 31, 2016, we had 187.1 MMBOE of2019, estimated proved undeveloped reserves which is a decrease of 39.7decreased 43.7 MMBOE, or 1817 percent from 226.8 MMBOE atcompared with December 31, 2015.2018. The following table provides a reconciliation of our proved undeveloped reserves for the year ended December 31, 2016:2019:
|
| | |
| | Total (MMBOE) |
| Total proved undeveloped reserves: | |
| Beginning of year | 226.8258.6 |
|
Revisions of previous estimates (1) | (34.347.6 | ) |
Additions from discoveries, extensions, and infill (2) | 89.478.5 |
|
Sales of reserves | (17.1 | ) |
Purchases of minerals in place(3) | 8.11.9 |
|
Removed for five-year rule (4) | (43.09.8 | ) |
Conversions to proved developed (5) | (42.866.7 | ) |
End of year(6) | 187.1214.9 |
|
Revisions of previous estimates. Revisions of previous estimates includes a downward pricing revision of 42.3 MMBOE from our South Texas program as a result of decreased gas and NGL prices. In addition, we had downward performance revisions of 6.0 MMBOE in our Midland Basin program as we updated certain assumptions based on future well spacing.
| |
(1)
| Revisions of previous estimates relate to a negative price revision of 25.5 MMBOE due to the decline in commodity prices during 2016 and a negative performance revision of 8.8 MMBOE. |
| |
(2)
| We added 78.4 MMBOE of infill proved undeveloped reserves and an additional 11.0 MMBOE of proved undeveloped reserves through extensions and discoveries primarily in our Eagle Ford shale program. |
| |
(3)
| We acquired 8.1 MMBOE of proved undeveloped reserves primarily in the Midland Basin. As of December 31, 2016, a relatively small portion of our future development capital was allocated to proved reserve locations. The remainder of capital allocated was to delineate our extensive acquired Midland Basin acreage position, still classified as unproven. We expect reserve growth over time as additional acreage is classified as proven and capital is allocated to offset locations. |
| |
(4)
| Proved undeveloped reserves were reduced by 43.0 MMBOE due to changes in our development plan, which caused these locations to be reclassified primarily to the probable reserves category due to the five-year rule. These locations were replaced by higher quality proved undeveloped reserves, which are classified as extensions or infills in the table above, and resulted from our testing and delineation programs. |
| |
(5)
| Conversions of proved undeveloped reserves to proved developed reserves were primarily in our Eagle Ford shale and Bakken/Three Forks programs. Our 2016 track record was slightly below 20 percent due to fewer conversions of proved undeveloped reserves in our Raven/Bear Den program, which we sold during the fourth quarter of 2016, and in our outside-operated Eagle Ford shale program due to the operator curtailing activity in 2016. Our 2016 development pace and our multi-year historical track record were both in excess of 20 percent. During 2016, we incurred approximately $268 million on projects associated with reserves booked as proved undeveloped reserves at the end of 2015, of which approximately $226 million was spent on proved undeveloped reserves converted to proved developed reserves by December 31, 2016. At December 31, 2016, drilled but not completed wells represented 28.0 MMBOE of total proved undeveloped reserves. We expect to incur approximately $145 million of capital expenditures in completing these wells, and we expect all of these wells to be completed within five years from their initial booking as proved undeveloped reserves. |
| |
(6)
| As of December 31, 2016, none of our proved undeveloped reserves were on acreage expected to expire before their targeted completion date. |
Additions from discoveries, extensions, and infill. We added 40.8 MMBOE and 30.4 MMBOE of infill estimated proved undeveloped reserves in our Midland Basin and South Texas assets, respectively, in 2019. We added an additional 3.1 MMBOE and 4.1 MMBOE of estimated proved undeveloped reserves in the Midland Basin and South Texas, respectively, through various extensions and discoveries. The majority of additions in our Midland Basin and South Texas programs resulted from future development projects identified by our on-going development and portfolio optimization activities.
Removed for five-year rule. As a result of our testing and delineation efforts in 2019, we revised certain aspects of our future development plans to focus on maximizing returns and the value of our assets. As a result, we removed 9.8 MMBOE of estimated proved undeveloped reserves and reclassified these locations to unproved reserve categories. The reclassified locations were generally replaced by locations with higher quality proved undeveloped reserves, which are reflected as additions from discoveries, extensions, and infill.
Conversions to proved developed. Our 2019 conversion rate was 26 percent. During 2019, we incurred $686.3 million on projects with reserves booked as proved undeveloped at the end of 2018, of which $611.1 million was spent on converting proved undeveloped reserves to proved developed reserves by December 31, 2019. At December 31, 2019, drilled but not completed wells represented 26.8 MMBOE of total estimated proved undeveloped reserves. We expect to incur $182.0 million of capital expenditures in completing these drilled but not completed wells, and we expect all estimated proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as proved undeveloped reserves.
As of December 31, 2016,2019, estimated future development costs relating to our proved undeveloped reserves were approximately $181$591.5 million, $378$615.6 million, and $402$458.1 million in 2017, 2018,2020, 2021, and 2019,2022, respectively.
Internal Controls Over Proved Reserves Estimates
Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to our corporate reserves group and is coordinated by our Corporate Business Development Director,Engineering Manager, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below. Our Corporate Business Development DirectorEngineering Manager has over 25approximately 12 years of experience in the energy industry and has been employed by the Company for 10 years. He holds a Bachelor of Science Degree in Petroleum Engineering from Montana Tech of Thethe University of Montana and is a Registered Professional Petroleum Engineer in the states of Texas, Wyoming and Montana. He is also a member of the
Society of Petroleum Engineers. Technical, geological, and engineering reviews of our assets are performed throughout the year by our regional staff. This data,Data, obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. Our regional engineering technical staff do not report directly to our Corporate Business Development Director;Engineering Manager; they report to either their respective regional technical managers or directly to the regional manager. This design is intended to promote objective and independent analysis within our regions in the proved reserves estimation process.
Third-party Reserves Audit
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over 70 years. Ryder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the proved reserve amounts of our audited properties determined by Ryder Scott are required, per our policy, to be within 10 percent of our proved reserve amounts for the total company,Company, as well as for each respective region. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over 70 years. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is an Advising Senior Vice President who received a Bachelor of Science Degreedegree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degreedegree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. The 2019 Ryder Scott 2016 report concerning our reserves is included as Exhibit 99.1.
In addition to a third-party audit, our reserves are reviewed by our management with the Audit Committee of our Board of Directors. Management,Our management, which includes our President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and Executive Vice President - Operations,and Chief Operating Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives, apart from our management, from time to time to discuss processes and findings.
Production
The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties in which we held an interest during the periods indicated.presented. Realized prices presented below exclude the effects of derivative contract settlements. Also presented is a summary of related production costsexpense on a per BOE basis.
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
Net production (2) | | | | | | |
| Net production volumes | | | | | | |
| Oil (MMBbl) | 16.6 |
| | 19.2 |
| | 16.7 |
| 21.9 |
| | 18.8 |
| | 13.7 |
|
| Gas (Bcf) | 146.9 |
| | 173.6 |
| | 152.9 |
| 109.8 |
| | 103.2 |
| | 123.0 |
|
| NGLs (MMBbl) | 14.2 |
| | 16.1 |
| | 13.0 |
| 8.1 |
| | 7.9 |
| | 10.3 |
|
MMBOE (3) | 55.3 |
| | 64.2 |
| | 55.1 |
| |
Eagle Ford net production (1)(2) | | | | | | |
Equivalent (MMBOE) (1) | | 48.3 |
| | 43.9 |
| | 44.5 |
|
Midland Basin net production volumes (2) | | | | | | |
| Oil (MMBbl) | 5.4 |
| | 7.6 |
| | 6.9 |
| 20.5 |
| | 16.6 |
| | 8.5 |
|
| Gas (Bcf) | 129.9 |
| | 147.2 |
| | 120.6 |
| 34.4 |
| | 25.8 |
| | 14.7 |
|
| NGLs (MMBbl) | 13.8 |
| | 15.6 |
| | 12.7 |
| — |
| | — |
| | — |
|
MMBOE (3) | 40.9 |
| | 47.7 |
| | 39.7 |
| |
Equivalent (MMBOE) (1) | | 26.3 |
| | 20.9 |
| | 11.0 |
|
Eagle Ford shale net production volumes (2)(3) | | | | | | |
| Oil (MMBbl) | | 1.3 |
| | 1.2 |
| | 1.9 |
|
| Gas (Bcf) | | 75.4 |
| | 76.1 |
| | 104.0 |
|
| NGLs (MMBbl) | | 8.1 |
| | 7.9 |
| | 10.1 |
|
Equivalent (MMBOE) (1) | | 21.9 |
| | 21.8 |
| | 29.3 |
|
| Realized price, before the effect of derivative settlements | | | | | | | | | | |
| Oil (per Bbl) | $ | 36.85 |
| | $ | 41.49 |
| | $ | 80.97 |
| $ | 54.10 |
| | $ | 56.80 |
| | $ | 47.88 |
|
| Gas (per Mcf) | $ | 2.30 |
| | $ | 2.57 |
| | $ | 4.58 |
| $ | 2.39 |
| | $ | 3.43 |
| | $ | 3.00 |
|
| NGLs (per Bbl) | $ | 16.16 |
| | $ | 15.92 |
| | $ | 33.34 |
| $ | 17.26 |
| | $ | 27.22 |
| | $ | 22.35 |
|
| Per BOE | $ | 21.32 |
| | $ | 23.36 |
| | $ | 45.01 |
| $ | 32.84 |
| | $ | 37.27 |
| | $ | 28.20 |
|
| Production costs per BOE | | | | | | |
| Production expense per BOE | | | | | | |
| Lease operating expense | $ | 3.51 |
| | $ | 3.73 |
| | $ | 4.28 |
| $ | 4.67 |
| | $ | 4.74 |
| | $ | 4.43 |
|
| Transportation costs | $ | 6.16 |
| | $ | 6.02 |
| | $ | 6.11 |
| $ | 3.88 |
| | $ | 4.36 |
| | $ | 5.48 |
|
| Production taxes | $ | 0.94 |
| | $ | 1.13 |
| | $ | 2.13 |
| $ | 1.35 |
| | $ | 1.52 |
| | $ | 1.18 |
|
| Ad valorem tax expense | $ | 0.21 |
| | $ | 0.39 |
| | $ | 0.46 |
| $ | 0.48 |
| | $ | 0.48 |
| | $ | 0.34 |
|
| |
(1) | InAmounts may not calculate due to rounding. |
| |
(2) | For each of the years 2016, 2015,ended December 31, 2019, 2018, and 2014,2017, total estimated proved reserves attributed to our Midland Basin assets and our Eagle Ford shale propertiesassets exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis. |
| |
(2)(3)
| AsDuring the first quarter of December 31, 2016,2017, we completed the divestiture of our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing date in the first quarter of 2017.assets. These assets represented approximately 9.71.5 MMBOE of net production on an equivalent basis for the year ended December 31, 2016.2017. |
| |
(3)
| Amounts may not calculate due to rounding. |
Productive Wells
As of December 31, 2016,2019, we had working interests in 1,027807 gross (841(758 net) productive oil wells and 1,882519 gross (704(487 net) productive gas wells. Productive wells are eitherexploratory, development, or extension wells that are producing, in commercial quantities or wells mechanicallyare capable of commercial production but areof oil, gas, and/or NGLs. Productive wells may be temporarily shut-in. Multiple completions in the same wellbore are counted as one well. As of December 31, 2016, three2019, two of these wells had multiple completions. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil when it first commenced production, but such designation may not be indicative of current production.or future production composition.
Drilling and Completion Activity
All of our drilling and completion activities are conducted by independent contractors. We do not own any drilling or completion equipment. The following table summarizes the number of operated and outside-operated wells drilled and completed or recompleted on our properties in 2016, 2015,2019, 2018, and 2014,2017, excluding non-consented projects, active injector wells, salt water disposal wells, and anyor wells in which we own only a royalty interest:
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Development wells: | | | | | | | | | | | | |
| Development wells | | | | | | | | | | | | |
| Oil | 100 |
| | 73.0 |
| | 87 |
| | 56.5 |
| | 133 |
| | 66.1 |
| 119 |
| | 107 |
| | 103 |
| | 92 |
| | 56 |
| | 46 |
|
| Gas | 114 |
| | 56.1 |
| | 272 |
| | 100.8 |
| | 476 |
| | 165.5 |
| 27 |
| | 16 |
| | 39 |
| | 24 |
| | 38 |
| | 35 |
|
| Non-productive | 2 |
| | 1.1 |
| | — |
| | — |
| | 8 |
| | 5.3 |
| 1 |
| | 1 |
| | — |
| | — |
| | 4 |
| | 3 |
|
| | 216 |
| | 130.2 |
| | 359 |
| | 157.3 |
| | 617 |
| | 236.9 |
| 147 |
| | 124 |
| | 142 |
| | 116 |
| | 98 |
| | 84 |
|
| Exploratory wells: | | | | | | | | | | | | |
| Exploratory wells | | | | | | | | | | | | |
| Oil | 7 |
| | 6.8 |
| | 5 |
| | 3.5 |
| | 5 |
| | 3.0 |
| 4 |
| | 4 |
| | 18 |
| | 14 |
| | 32 |
| | 29 |
|
| Gas | — |
| | — |
| | 1 |
| | 1.0 |
| | 7 |
| | 4.8 |
| 4 |
| | 4 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Non-productive | — |
| | — |
| | 5 |
| | 4.1 |
| | 4 |
| | 3.3 |
| 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
|
| | 7 |
| | 6.8 |
| | 11 |
| | 8.6 |
| | 16 |
| | 11.1 |
| 9 |
| | 9 |
| | 19 |
| | 15 |
| | 33 |
| | 29 |
|
| Total | 223 |
| | 137.0 |
| | 370 |
| | 165.9 |
| | 633 |
| | 248.0 |
| 156 |
| | 133 |
| | 161 |
| | 131 |
| | 131 |
| | 113 |
|
A productive well is an exploratory, development, or extension well that is producing or is capable of commercial production of oil, gas, and/or NGLs. A non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development, or extension well that proves to be incapable of producing oil, gas, and/or NGLs in sufficient commercial quantities to justify completion, or upon completion, the economic operation of a well.
As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry well,hole, the reporting to the appropriate authority that the well has been plugged and abandoned.
In addition to the wells drilled and completed in 20162019 (included in the table above), seewe were actively participating in the table below for additional drilling of 22 gross (20 net) wells and completion activity in progresshad 66 gross (63 net) drilled but not completed wells as of the date noted below: January 31, 2020. These drilled but not completed wells represent wells that were being completed or were waiting on completion as of January 31, 2020.
|
| | | | | |
| | As of January 31, 2017 |
| | Gross | | Net |
Drilling: (2) | | | |
| Operated | 9 |
| | 8.9 |
|
| Outside-operated | 24 |
| | 5.0 |
|
| Total | 33 |
| | 13.9 |
|
| | | | |
Drilled but not completed: (1) (2) | | | |
| Operated | 81 |
| | 77.7 |
|
| Outside-operated | 133 |
| | 24.8 |
|
| Total | 214 |
| | 102.5 |
|
| |
(1)
| Represents wells that were being completed or waiting on completion as of January 31, 2017. |
| |
(2)
| Subsequent to December 31, 2016, we executed a definitive sales agreement for our outside-operated Eagle Ford shale assets and announced our plans to sell our remaining Williston Basin assets in Divide County, North Dakota in 2017. As of January 31, 2017, we were participating in the drilling of 22 gross (4 net) outside-operated wells related to these assets. The drilled but not completed wells presented above include 20 gross (17 net) operated wells and 132 gross (24 net) outside-operated wells related to these assets. |
Acreage
The following table sets forth the number of gross and net surface acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes that we held as of December 31, 2016.2019. Undeveloped acreage includes leasehold interests containing proved undeveloped reserves.
|
| | | | | | | | | | | | | | | | | |
| | Developed Acres (1) | | Undeveloped Acres (2)(3) | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| South Texas & Gulf Coast: | | | | | | | | |
|
| |
|
|
| Operated Eagle Ford | 69,777 |
| | 67,960 |
| | 97,175 |
| | 93,525 |
| | 166,952 |
| | 161,485 |
|
Outside-operated Eagle Ford (5) | 139,383 |
| | 24,893 |
| | 89,900 |
| | 10,929 |
| | 229,283 |
| | 35,822 |
|
| Other | 5,780 |
| | 869 |
| | 7,783 |
| | 5,771 |
| | 13,563 |
| | 6,640 |
|
| Permian: | | | | | | | | | | | |
RockStar (4) | 32,641 |
| | 26,632 |
| | 48,419 |
| | 35,338 |
| | 81,060 |
| | 61,970 |
|
| Sweetie Peck | 15,020 |
| | 14,409 |
| | 361 |
| | 192 |
| | 15,381 |
| | 14,601 |
|
| Halff East | 9,080 |
| | 5,468 |
| | 1,490 |
| | 516 |
| | 10,570 |
| | 5,984 |
|
| Rocky Mountain: | | | | | | | | |
|
| |
|
|
| North Rockies: | | | | | | | | |
|
| |
|
|
Divide (6) | 165,510 |
| | 110,625 |
| | 24,283 |
| | 12,943 |
| | 189,793 |
| | 123,568 |
|
Other (7) | — |
| | — |
| | 244,371 |
| | 172,148 |
| | 244,371 |
| | 172,148 |
|
| South Rockies: | | | | | | | | |
|
| |
|
|
| PRB Cretaceous | 50,429 |
| | 38,625 |
| | 141,116 |
| | 117,637 |
| | 191,545 |
| | 156,262 |
|
Other (7) | 1,316 |
| | 987 |
| | 103,921 |
| | 85,126 |
| | 105,237 |
| | 86,113 |
|
Other (8) | 10,499 |
| | 10,499 |
| | 18,891 |
| | 16,232 |
| | 29,390 |
| | 26,731 |
|
| Total | 499,435 |
| | 300,967 |
| | 777,710 |
| | 550,357 |
| | 1,277,145 |
| | 851,324 |
|
|
| | | | | | | | | | | | | | | | | |
| | Developed Acres (1) | | Undeveloped Acres (2)(3) | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Midland Basin: | | | | | | | | | | | |
| RockStar | 67,113 |
| | 59,589 |
| | 4,966 |
| | 4,217 |
| | 72,079 |
| | 63,806 |
|
| Sweetie Peck | 17,007 |
| | 15,782 |
| | 2,835 |
| | 251 |
| | 19,842 |
| | 16,033 |
|
Midland Basin Total (4) | 84,120 |
| | 75,371 |
| | 7,801 |
| | 4,468 |
| | 91,921 |
| | 79,839 |
|
| Eagle Ford shale | 74,247 |
| | 71,296 |
| | 88,058 |
| | 87,631 |
| | 162,305 |
| | 158,927 |
|
Other (5) | 16,259 |
| | 11,363 |
| | 90,415 |
| | 25,599 |
| | 106,674 |
| | 36,962 |
|
| Total | 174,626 |
| | 158,030 |
| | 186,274 |
| | 117,698 |
| | 360,900 |
| | 275,728 |
|
| |
(1) | Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as developed acreage in the presentationtable above. |
| |
(2) | Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. |
| |
(3) | As of the filing date of this report,February 6, 2020, approximately 35,900, 20,200,1,354, 184, and 7,900155 net acres of undeveloped acreage are scheduled to expire by December 31, 2017, 2018,2020, 2021, and 2019,2022, respectively, if production is not established or we take no other action to extend the terms of the applicable leases. Certain of our Eagle Ford shale acreage is subject to lease or leases.consolidation agreements containing drilling, completion, and other obligations that we currently intend to satisfy. Failure to meet these obligations results in termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous development obligations required by individual leases are not met. |
| |
(4) | Refers to our recently acquiredAs of December 31, 2019, total Midland Basin acreage in Howard and Martin Counties, Texas.excludes approximately 1,940 net acres associated with drill-to-earn opportunities that we intend to pursue. |
| |
(5) | Our outside-operated Eagle Ford shale assets were held for sale as of December 31, 2016. Subsequent to year-end 2016, we entered into a definitive agreement with an expected closing date in the first quarter of 2017. |
| |
(6)
| Subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets. |
| |
(7)
| Includes other non-core acreage located in Louisiana, Montana, North Dakota, Montana, Wyoming,Texas, Utah, and Utah. |
| |
(8)
| Includes Louisiana fee and other non-core acreage.Wyoming. |
Delivery Commitments
As of December 31, 2016,2019, we had gathering, processing, and transportation throughput, and delivery commitments with various third partiesthird-parties that have aggregaterequire delivery of a minimum commitments to deliver 1,461quantity of 24 MMBbl of oil and 424 Bcf of natural gas 70through 2023, and 18 MMBbl of crude oil, 13 MMBbl of NGLs, and 25 MMBbl ofproduced water through 2034.2027. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for natural gas is projected, we have rightscommitments under certain contracts to arrange forthird party gas to be delivered, and such volume will count toward our minimum volume commitment. Our current production is insufficient to offset these aggregate contractual liabilities, but weagreements. We expect to fulfill theour delivery commitments withfrom a combination of production from theour existing productive wells, future development of our proved undeveloped reserves, and from the future development of resources not yet characterized as proved reserves or through arranging forreserves. Under certain of our commitments, if we are unable to deliver the deliveryminimum quantity from our production, we may deliver production acquired from third-parties to satisfy our minimum volume commitments.
As of third party gas. InDecember 31, 2019, in the event that no product isadditional volumes are delivered in accordance with these agreements, the aggregate undiscounted future deficiency payments would have beentotal $218.5 million. This amount does not include deficiency payment estimates associated with approximately $970.9 million as of December 31, 2016. Please refer to Note 6 - Commitments and Contingencies in Part II, Item 8 for additional discussion.
Subsequent to December 31, 2016, we entered into a definitive agreement for the sale of our outside-operated Eagle Ford shale assets held for sale at December 31, 2016, and expect to close the transaction in the first quarter of 2017. Upon closing the sale, we would no longer be subject to transportation throughput commitments totaling 514 Bcf of natural gas, 5216.5 MMBbl of future oil delivery commitments where we cannot predict with accuracy the amount and 13 MMBbltiming of NGLs, or $501.9 millionthese payments, as such payments are dependent upon the price of potential undiscounted deficiency payments. Please refer tooil in effect at the caption Major Customers below, as our operator in our outside-operated Eagle Ford shale program is identified as a major customer under the various marketing agreements we were party to astime of December 31, 2016.
settlement.
As of the filing date of this report, we do not expect to incur any material shortfalls.shortfalls with regard to these commitments.
Major Customers
We do not believe the loss of any single purchaser of our crude oil, natural gas, and NGLsproduction would materially impact our operating results, as theseoil, gas, and NGLs are products with well-established markets and numerous purchasersother viable purchaser options are presentavailable in our operating regions.
We had theThe following major customercustomers and sales to entities under common ownership, whichcontrol accounted for 10 percent or more of our total oil, gas, and NGL production revenue for at least one of the periods presented:
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
Major customer (1) | 18 | % | | 21 | % | | 19 | % |
Group #1 of entities under common ownership (2) | 15 | % | | 10 | % | | 14 | % |
Group #2 of entities under common ownership (2) | 8 | % | | 11 | % | | 9 | % |
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
Major customer #1 (1) | 18 | % | | 18 | % | | 6 | % |
Major customer #2 (1) | 14 | % | | 5 | % | | 1 | % |
Major customer #3 (1) | 13 | % | | 7 | % | | — | % |
Major customer #4 (1) | 9 | % | | 10 | % | | 10 | % |
Group #1 of entities under common control (2) | 13 | % | | 18 | % | | 17 | % |
Group #2 of entities under common control (2) | 11 | % | | 12 | % | | 8 | % |
| |
(1) | ThisThese major customer is our operator in our outside-operated Eagle Ford shale program, which we entered into various marketing agreements with during 2013, whereby wecustomers are subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because we share with our operator the riskpurchasers of non-performance by its counterparty purchasers, we have included our operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasersportion of our production from other areas. As of December 31, 2016, our outside-operated Eagle Ford shale assets were classified as held for sale.Midland Basin assets. |
| |
(2) | In the aggregate, these groups of entities under common ownership representcontrol represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for the period(s) shown; however, noneat least one of the entitiesperiods presented; however, no individual entity comprising either group individually representedwas a purchaser of more than 10 percent of our total oil, gas, and NGL production revenue. |
Employees and Office Space
As of February 15, 2017,6, 2020, we had 607530 full-time employees. This is a 2313 percent decrease from the 786 reported611 full-time employees that we reported as of February 17, 2016.7, 2019. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be good.agreement.
The following table summarizes the approximate square footage of office space leased by us, as of December 31, 2016,2019, including our corporate headquarters and regional offices:
|
| | | |
Region | | Approximate Square Footage Leased |
| Corporate | | 108,000107,000 |
|
PermianMidland Basin | | 54,00059,000 |
|
South Texas & Gulf Coast | | 64,00062,000 |
|
Rocky Mountain (1)
| | — |
|
Mid-Continent (2)
| | 50,000 |
|
| Total | | 276,000228,000 |
|
| |
(1)
| During the fourth quarter of 2016, we closed our office in Billings, Montana, and we executed an agreement to terminate the lease effective November 11, 2016. Please refer to Note 14 - Exit and Disposal Costsin Part II, Item 8 for additional discussion.
|
| |
(2)
| During the third quarter of 2015, we closed our office in Tulsa, Oklahoma. We have subleased this space through 2019 and our lease expires in 2022. Please refer to Note 14 - Exit and Disposal Costs in Part II, Item 8 for additional discussion.
|
In addition to the leased office space summarized in the table above, as of December 31, 2019, we own a total of 58,500owned approximately 12,000 square feet of office space in our South Texas & Gulf Coast and Rocky Mountain regions.Texas.
Title to Properties
Substantially all of our interestsoil and gas producing assets are held pursuant to oil and gas leases from third parties.third-party mineral owners. We usually obtain title opinions prior to commencing our initial drilling operations on our properties.the properties we operate. We have obtained title opinions or have conducted other title review on substantially all of our producing properties and believe we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry.properties. Most of our producing properties are subject to mortgages securing indebtedness under our Credit Agreement, royalty and overriding royalty interests, liens for current taxes, and other ordinary course burdens that we believe do not materially interfere with the use of, or affect the valuedevelopment of such properties. We typically perform only minimal title investigation in accordance with standards generally accepted in the oil and gas industry before acquiring developed and undeveloped leasehold acreage.
Seasonality
Generally, but not always,The price of crude oil is primarily driven by global socioeconomic factors and is less affected by seasonal fluctuations; however, demand for energy is generally higher in the winter and the summer driving season. The demand and price levels for natural gas increasefrequently increases during winter months and decreasedecreases during summer months. To lessen the impact of seasonal gas demand and price fluctuations, pipelines, utilities, local distribution companies, and industrial users regularly utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can divert gas that is traditionally is placed into storage. This could reducestorage which, in turn, may increase the typical winter seasonal price differential. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand.price. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Recently, the impact of seasonality on oil has been somewhat muted by overall supply and demand economics attributable to worldwide production in excess of existing worldwide demand.
Certain of our drilling, completion, and other operations are also subject to seasonal limitations. Seasonal weather conditions, government regulations, and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. See Please refer to Risk Factors - Risks Related to Our Businessbelow for additional discussion.
Competition
The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our acreage positions provide a foundation for development activities that we expect to fuel our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which in some cases have larger technical staffsteams and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have gathering, processing or refining operations, market refined products, provide, dispose of and transport fresh and produced water, own drilling rigs or otherproduction equipment, or generate electricity.
We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells, as well as for the gathering, transporting, and processing of crude oil, natural gas, NGLs and NGLs.water. Consequently, we may face shortages, delays, or increased costs in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including renewable energy sources such as solar and wind-generated energy, and other fossil fuels such as coal and imported liquefied natural gas.coal. Competitive conditions may be affected by future energy, climate-related, financial, or other policies, legislation, and regulations.
In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to the evolving demographics of our industry. We are not insulated from the competition for quality people, and we must compete effectively in order to be successful.
Government RegulationsCautionary Information about Forward-Looking Statements
OurThis Annual Report on Form 10-K (“Form 10-K”) contains “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 facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations, business is extensively controlled by numerous federal, state,prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and local lawsobjectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “intend,” “pending,” “plan,” “potential,” “project,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:
the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”);
our outlook on future crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this document) prices, well costs, service costs, lease operating costs, and general and administrative costs;
the drilling of wells and other exploration and development activities, the ability to obtain permits and governmental regulations.approvals, and plans by us, our joint development partners, and/or other third-party operators;
possible or expected acquisitions and divestitures, including the possible divestiture or farm-down of, or joint venture relating to, certain properties;
oil, gas, and NGL reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;
future oil, gas, and NGL production estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;
cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;
plans, objectives, expectations and intentions; and
| |
| • | other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report. |
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These lawsstatements are subject to known and regulationsunknown risks and uncertainties, which may cause our actual results and performance to be changedmaterially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in Part I, Item 1A, Risk Factors - Risks Related to Our Business below and elsewhere in this report. The forward-looking statements in this report speak as of the filing of this report. Although, we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.
Glossary of Oil and Gas Terms
The oil and gas terms defined in responsethis section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the Securities and Exchange Commission’s (“SEC”) website at www.sec.gov.
Ad valorem tax. A tax based on the value of real estate or personal property.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to economic or political conditions,oil, NGLs, water, or other developments,liquid hydrocarbons.
BBtu. One billion British thermal units.
Bcf.One billion cubic feet, used in reference to gas.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas to one Bbl of oil or NGLs.
Btu. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Developed acreage.The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and our regulatory burden may increaseoperating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (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.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil, gas, and/or NGLs in commercial quantities.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and gas) rights.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.
Lease operating expenses. The expenses incurred in the future. Lawslifting of oil, gas, and/or NGLs from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.
MBbl. One thousand barrels of oil, NGLs, water, or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet, used in reference to gas.
MMBbl. One million barrels of oil, NGLs, water, or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet, used in reference to gas.
Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.
NGLs.The combination of ethane, propane, isobutane, normal butane, and natural gasoline that when removed from gas become liquid under various levels of higher pressure and lower temperature.
NYMEX WTI. New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for oil.
NYMEX Henry Hub. New York Mercantile Exchange Henry Hub, a common industry benchmark price for gas.
OPIS. Oil Price Information Service, a common industry benchmark for NGL pricing at Mont Belvieu, Texas.
PV-10 (Non-GAAP). PV-10 is a non-GAAP measure. The present value of estimated future revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.
Productive well. A well that is producing oil, gas, and/or NGLs or that is capable of commercial production of those products.
Proved reserves. Those quantities of oil, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Recompletion. The completion of an existing wellbore in a formation other than that in which the well has previously been completed.
Reserve life index. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil, gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resource play. A term used to describe an accumulation of oil, gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has lower expected geological risk.
Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from oil, gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.
Royalty interest. An interest in an oil and gas property entitling the owner to shares of oil, gas, and NGL production free of costs of exploration, development, and production operations.
Seismic. Thesending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
Standardized measure of discounted future net cash flows. The discounted future net cash flows related to estimated proved reserves based on prices used in estimating the reserves, year end costs, and statutory tax rates, at a 10 percent annual discount rate. The information for this calculation is included in Supplemental Oil and Gas Information (unaudited) located in Part II, Item 8 of this report.
Track record. Current year conversions of proved undeveloped reserves to proved developed reserves, divided by beginning of the year proved undeveloped reserves.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the potentialproduction of commercial quantities of oil, gas, and NGLs regardless of whether such acreage contains estimated net proved reserves.
Undeveloped reserves. Reserves that are expected to increase our costbe recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The applicable SEC definition of doing businessundeveloped reserves provides that 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.
Working interest. The operating interest that gives the owner the right to drill, produce, and consequently could affect our profitability. However,conduct operating activities on the property and to share in the production, sales, and costs.
PART I
When we do not believe thatuse the terms “SM Energy,” the “Company,” “we,” “us,” or “our,” we are affectedreferring to a materially greaterSM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business in the Glossary of Oil and Gas Terms section of this report. Throughout this document we make statements and projections that address future expectations, possibilities, or lesser extent than othersevents, all of which may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this report for an explanation of these types of statements and the associated risks and uncertainties.
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
We are an independent energy company engaged in our industry.
Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing theacquisition, exploration, fordevelopment, and production of oil, gas, and NGLs including lawsin the state of Texas. SM Energy was founded in 1908, incorporated in Delaware in 1915, and regulations requiring permitsour initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”
Our principal office is located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Strategy
At SM Energy, our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision for the drillingCompany is to sustainably grow value for all of wells, imposing bond requirementsour stakeholders. We believe that in order to drill or operateaccomplish this vision, we must be a premier operator of top tier assets. Our current energy project development portfolio is focused on oil and gas producing properties in the state of Texas.
Significant Developments in 2019
Strategic Transformation. During 2019, we completed our strategic transformation, which commenced in 2016 through a series of asset acquisitions and divestitures. For the fourth quarter of 2019, we passed an important milestone by achieving a positive difference between our net cash provided by operating activities and our net cash used in investing activities. Our operational execution in 2019 was outstanding, achieving our objectives in important industry metrics, including key top-quartile benchmarks for environmental, health, and safety performance. We were also successful in proving up additional investment opportunities on our existing acreage positions.
Production. Our average daily production in 2019 consisted of 59.9 MBbl of oil, 300.8 MMcf of gas, and 22.2 MBbl of NGLs, for an average net daily equivalent production rate of 132.3 MBOE, which represented a 10 percent increase compared with 2018. This increase was primarily driven by a 25 percent increase in production volumes from our Midland Basin assets as a result of strong well performance, increased drilling and completion efficiencies, improved completion designs, and longer laterals. We completed more lateral feet in 2019 compared with 2018, driving continued increases in volumes at a lower average drilling and completion cost. On a retained asset basis, our production volumes increased 13 percent in 2019. As a result of the above, oil production revenue was approximately 75 percent of total production revenue for the year ended December 31, 2019, compared with 65 percent and 52 percent for the years ended December 31, 2018 and 2017, respectively. Please refer to Areas of Operationbelow for additional discussion.
Reserves and Capital Investment. Our estimated proved reserves decreased eight percent to 462.0 MMBOE at December 31, 2019, from 503.4 MMBOE at December 31, 2018. Reserve additions from discoveries, extensions, and infills totaled 98.4 MMBOE and were a result of our successful development programs, completion optimizations that resulted in improved well performance, and development plan improvements that we believe will enhance inventory value. The 2019 reserve additions were offset by 2019 production volumes of 48.3 MMBOE and by downward revisions of 94.7 MMBOE, which resulted primarily from the impact of lower commodity prices. Our proved reserve life index decreased to 9.6 years as of December 31, 2019, compared with 11.5 years as of December 31, 2018. Costs incurred for development and exploration activities, excluding acquisitions, decreased 23 percent from the prior year to $1.0 billion in 2019. Please refer to Areas of Operationand Reservesbelow, and to Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report for additional discussion.
Net Cash Provided by Operating Activities. Net cash provided by operating activities was $823.6 million for the year ended December 31, 2019, compared with $720.6 million for the year ended December 31, 2018, which was an increase of 14 percent year-over-year. Oil, gas, and NGL production revenues decreased for the year ended December 31, 2019, compared with 2018, as the impact from higher production volumes was offset by lower commodity prices. However, the impact of lower commodity prices in 2019 was offset by a net derivative cash settlement gain of $39.2 million for the year ended December 31, 2019, compared to a net derivative cash settlement loss of $135.8 million for 2018. Please refer to Analysis of Cash Flow Changes Between 2019 and 2018 and Between
2018 and 2017 in Overview of Liquidity and Capital Resourcesin Part II, Item 7, and to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Outlook
Our business outlook for the next several years is a continuation of our trajectory of improving operating margins and cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics. Our total capital program in 2020, is budgeted to be between $825.0 million and $850.0 million, and is expected to be approximately 20% lower compared with 2019, in large part due to significant cost reductions and efficiencies that were achieved in 2019. Our 2020 program will be focused on highly economic oil development projects in both our Midland Basin and South Texas assets. We expect total production volumes in 2020 to decrease slightly compared with 2019 as expected continued growth in our oil production volumes will not completely offset expected decreases in gas and NGL production volumes.
Sustainability is a key focus of our plans, in terms of positioning ourselves financially to participate in future energy investment opportunities, and executing our strategy of being a premier operator with high standards for corporate responsibility. We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive difference in the communities where we live and work; and transparency in reporting on our progress in these areas.
Please refer to Overview of Liquidity and Capital Resources in Part II, Item 7 of this report for discussion of how we expect to fund our 2020 capital program.
Areas of Operation
Our 2019 operations were concentrated in the Midland Basin and South Texas, as further described below. The following table summarizes estimated proved reserves, production, and costs incurred in oil and gas producing activities (“costs incurred”) for the year ended December 31, 2019, for these areas:
|
| | | | | | | | | | | |
| Midland Basin | | South Texas | | Total (1) |
| Proved reserves | | | | | |
| Oil (MMBbl) | 167.5 |
| | 16.6 |
| | 184.1 |
|
| Gas (Bcf) | 398.8 |
| | 824.4 |
| | 1,223.2 |
|
| NGLs (MMBbl) | 0.1 |
| | 73.9 |
| | 74.0 |
|
MMBOE (1) | 234.1 |
| | 227.8 |
| | 462.0 |
|
| Relative percentage | 51 | % | | 49 | % | | 100 | % |
| Proved developed % | 49 | % | | 58 | % | | 53 | % |
| Production | | | | | |
| Oil (MMBbl) | 20.5 |
| | 1.3 |
| | 21.9 |
|
| Gas (Bcf) | 34.4 |
| | 75.4 |
| | 109.8 |
|
| NGLs (MMBbl) | — |
| | 8.1 |
| | 8.1 |
|
MMBOE (1) | 26.3 |
| | 22.0 |
| | 48.3 |
|
Avg. daily equivalents (MBOE/d) (1) | 72.0 |
| | 60.3 |
| | 132.3 |
|
| Relative percentage | 54 | % | | 46 | % | | 100 | % |
Costs incurred (in millions) (2) (3) | $ | 859.6 |
| | $ | 160.9 |
| | $ | 1,040.2 |
|
| |
(1) | Amounts may not calculate due to rounding. |
| |
(2) | Regional costs incurred do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activities that are excluded from this regional table. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report. |
| |
(3) | Costs incurred for 2019 included $11.3 million related to acquisitions of primarily unproved oil and gas properties in the Midland Basin. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report. |
Excluding acquisition activity, costs incurred decreased in 2019 by 23 percent compared with 2018 primarily due to increased operational efficiencies and decreased drilling, completion crew, and sand costs incurred in developing our Midland Basin assets. Total estimated proved reserves at year end 2019 decreased eight percent from 2018. Production increased 10 percent on an equivalent basis for the year ended December 31, 2019, compared with 2018, and increased 13 percent on a retained assets basis.
Midland Basin. Our Midland Basin assets are located within the Permian Basin in Western Texas and are comprised of approximately 80,000 net acres (“Midland Basin”). In 2019, we focused on continuing to delineate, develop, and expand our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
In 2019, we incurred $859.6 million of costs and averaged six drilling rigs and three completion crews. The majority of our Midland Basin capital was deployed on projects targeting the Lower Spraberry and Wolfcamp A and B intervals on our RockStar assets in Howard and Martin Counties, Texas and Sweetie Peck assets in Upton and Midland Counties, Texas. We completed 123 gross (111 net) wells and governingfull-year production increased 25 percent year-over-year to 26.3 MMBOE for 2019. As of December 31, 2019, there were 51 gross (48 net) wells that had been drilled but not completed in our Midland Basin program. Estimated proved reserves increased nine percent to 234.1 MMBOE at year end 2019, from 214.3 MMBOE at year end 2018. This increase was driven by additions of 58.9 MMBOE from discoveries, extensions and infill, and acquisitions, partially offset by 12.6 MMBOE of downward revisions from price, performance, and aged proved undeveloped reserves.
South Texas. Our South Texas assets are comprised of approximately 158,900 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on developing the timingEagle Ford shale formation and delineating the Austin Chalk formation. Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations covers a significant portion of the western Eagle Ford shale and Maverick Basin Austin Chalk (“Eagle Ford shale”) and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.
In 2019, we incurred $160.9 million of costs and averaged one drilling rig and one completion crew. We completed 31 gross (20 net) wells during 2019, and full-year regional production increased one percent year-over-year to 22.0 MMBOE for 2019. As of December 31, 2019, there were 21 gross (21 net) wells that had been drilled but not completed in our South Texas program.
Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to our joint development agreement. The agreement provided that the third party carried substantially all drilling and completion costs and receives a majority of the working and revenue interest in these wells until certain payout thresholds are reached. This arrangement allowed us to leverage third-party capital to prove up the value of our Eagle Ford North area, while also allowing us to test cutting edge technology, capture additional technical data, satisfy certain lease obligations, and potentially expand economic drilling inventory in the future. All wells subject to this agreement were drilled and completed as of December 31, 2019.
During 2019, we added 43.0 MMBOE of estimated proved reserves, offset by downward revisions of 82.1 MMBOE, of which 68.5 MMBOE resulted from decreased commodity pricing and 10.3 MMBOE resulted from performance revisions. As a result, estimated proved reserves decreased 21 percent to 227.8 MMBOE at year end 2019, from 289.1 MMBOE at year end 2018.
Reserves
Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. The following table presents the standardized measure of discounted future net cash flows and pre-tax PV-10 (“PV-10”). PV-10 is a non-GAAP financial measure, and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither the standardized measure of discounted future net cash flows nor PV-10 represents the fair market value of our oil and gas properties. We and others in the oil and gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held without regard to the specific tax characteristics of such entities. Please refer to the Glossary of Oil and Gas Terms section of this report for additional information regarding these measures and refer to the reconciliation of the standardized measure of discounted future net cash flows to PV-10 set forth below. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – Risks Related to Our Businessbelow.
Our ability to replace production with new oil and gas reserves is critical to the future success of our business. Please refer to the reserve life index term in the Glossary of Oil and Gas Terms section of this report for information describing how this metric is calculated.
The following table summarizes estimated proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP), the prices used in the calculation of proved reserves estimates, and reserve life index as of December 31, 2019, 2018, and 2017:
|
| | | | | | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 | | 2017 |
| Reserve data: | | | | | |
| Proved developed | | | | | |
| Oil (MMBbl) | 85.0 |
| | 68.2 |
| | 58.6 |
|
| Gas (Bcf) | 712.1 |
| | 699.1 |
| | 642.9 |
|
| NGLs (MMBbl) | 43.4 |
| | 60.1 |
| | 49.0 |
|
MMBOE (1) | 247.0 |
| | 244.8 |
| | 214.7 |
|
| Proved undeveloped | | | | | |
| Oil (MMBbl) | 99.1 |
| | 107.6 |
| | 99.6 |
|
| Gas (Bcf) | 511.1 |
| | 622.7 |
| | 637.2 |
|
| NGLs (MMBbl) | 30.6 |
| | 47.2 |
| | 47.6 |
|
MMBOE (1) | 214.9 |
| | 258.6 |
| | 253.4 |
|
Total proved (1) | | | | | |
| Oil (MMBbl) | 184.1 |
| | 175.7 |
| | 158.2 |
|
Gas (Bcf) (2) | 1,223.2 |
| | 1,321.8 |
| | 1,280.1 |
|
| NGLs (MMBbl) | 74.0 |
| | 107.4 |
| | 96.5 |
|
| MMBOE | 462.0 |
| | 503.4 |
| | 468.1 |
|
| Proved developed reserves % | 53 | % | | 49 | % | | 46 | % |
| Proved undeveloped reserves % | 47 | % | | 51 | % | | 54 | % |
| | | | | | |
| Reserve data (in millions): | | | | | |
| Standardized measure of discounted future net cash flows (GAAP) | $ | 4,104.0 |
| | $ | 4,654.4 |
| | $ | 3,024.1 |
|
| PV-10 (non-GAAP): | | | | | |
| Proved developed PV-10 | $ | 2,830.4 |
| | $ | 3,084.2 |
| | $ | 1,984.2 |
|
| Proved undeveloped PV-10 | 1,532.4 |
| | 2,020.1 |
| | 1,072.3 |
|
| Total proved PV-10 (non-GAAP) | $ | 4,362.8 |
| | $ | 5,104.3 |
| | $ | 3,056.5 |
|
| | | | | | |
12-month trailing average prices (3) | | | | | |
| Oil (per Bbl) | $ | 55.69 |
| | $ | 65.56 |
| | $ | 51.34 |
|
| Gas (per MMBtu) | $ | 2.58 |
| | $ | 3.10 |
| | $ | 3.00 |
|
| NGLs (per Bbl) | $ | 22.68 |
| | $ | 33.45 |
| | $ | 27.69 |
|
| | | | | | |
| Reserve life index (years) | 9.6 |
| | 11.5 |
| | 10.5 |
|
| |
(1) | Amounts may not calculate due to rounding. |
| |
(2) | For the years ended December 31, 2019, 2018, and 2017, proved gas reserves contained 44.9 Bcf, 59.1 Bcf, and 48.1 Bcf of gas, respectively, that we expect to produce and use as a field equipment fuel source (primarily to power compressors). |
| |
(3) | The prices used in the calculation of proved reserve estimates reflect the 12-month average of the first-day-of-the-month prices in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves. |
The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 (non-GAAP) of total estimated proved reserves. Please refer to the Glossary of Oil and Gas Termssection of this report forthe definitions of standardized measure of discounted future net cash flows and PV-10.
|
| | | | | | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Standardized measure of discounted future net cash flows (GAAP) | $ | 4,104.0 |
| | $ | 4,654.4 |
| | $ | 3,024.1 |
|
| Add: 10 percent annual discount, net of income taxes | 2,955.3 |
| | 3,847.1 |
| | 2,573.2 |
|
| Add: future undiscounted income taxes | 579.8 |
| | 1,012.2 |
| | 205.7 |
|
| Pre-tax undiscounted future net cash flows | 7,639.1 |
| | 9,513.7 |
| | 5,803.0 |
|
| Less: 10 percent annual discount without tax effect | (3,276.3 | ) | | (4,409.4 | ) | | (2,746.5 | ) |
| PV-10 (non-GAAP) | $ | 4,362.8 |
| | $ | 5,104.3 |
| | $ | 3,056.5 |
|
Proved Undeveloped Reserves
Proved undeveloped reserves include those reserves that are expected to be recovered from future wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2019, we did not have any proved undeveloped reserves that had been on our books in excess of five years, and none of our proved undeveloped reserves were on acreage expected to expire or on acreage that was not expected to be held through renewal before the targeted completion date.
For proved undeveloped locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic and engineering technology when booking estimated proved undeveloped reserves. Of the 214.9 MMBOE of total proved undeveloped reserves as of December 31, 2019, approximately 60.1 MMBOE of proved undeveloped reserves in the Midland Basin and 68.7 MMBOE of proved undeveloped reserves in our South Texas position were offset by more than one development spacing area from the nearest developed producing location. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected) and petrophysical analysis of that log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to development spacing areas that are immediately adjacent to developed spacing areas.
As of December 31, 2019, estimated proved undeveloped reserves decreased 43.7 MMBOE, or 17 percent compared with December 31, 2018. The following table provides a reconciliation of our proved undeveloped reserves for the year ended December 31, 2019:
|
| | |
| Total (MMBOE) |
| Total proved undeveloped reserves: | |
| Beginning of year | 258.6 |
|
| Revisions of previous estimates | (47.6 | ) |
| Additions from discoveries, extensions, and infill | 78.5 |
|
| Purchases of minerals in place | 1.9 |
|
| Removed for five-year rule | (9.8 | ) |
| Conversions to proved developed | (66.7 | ) |
| End of year | 214.9 |
|
Revisions of previous estimates. Revisions of previous estimates includes a downward pricing revision of 42.3 MMBOE from our South Texas program as a result of decreased gas and NGL prices. In addition, we had downward performance revisions of 6.0 MMBOE in our Midland Basin program as we updated certain assumptions based on future well spacing.
Additions from discoveries, extensions, and infill. We added 40.8 MMBOE and 30.4 MMBOE of infill estimated proved undeveloped reserves in our Midland Basin and South Texas assets, respectively, in 2019. We added an additional 3.1 MMBOE and 4.1 MMBOE of estimated proved undeveloped reserves in the Midland Basin and South Texas, respectively, through various extensions and discoveries. The majority of additions in our Midland Basin and South Texas programs resulted from future development projects identified by our on-going development and portfolio optimization activities.
Removed for five-year rule. As a result of our testing and delineation efforts in 2019, we revised certain aspects of our future development plans to focus on maximizing returns and the value of our assets. As a result, we removed 9.8 MMBOE of estimated proved undeveloped reserves and reclassified these locations to unproved reserve categories. The reclassified locations were generally replaced by locations with higher quality proved undeveloped reserves, which are reflected as additions from discoveries, extensions, and infill.
Conversions to proved developed. Our 2019 conversion rate was 26 percent. During 2019, we incurred $686.3 million on projects with reserves booked as proved undeveloped at the end of 2018, of which $611.1 million was spent on converting proved undeveloped reserves to proved developed reserves by December 31, 2019. At December 31, 2019, drilled but not completed wells represented 26.8 MMBOE of total estimated proved undeveloped reserves. We expect to incur $182.0 million of capital expenditures in completing these drilled but not completed wells, and we expect all estimated proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as proved undeveloped reserves.
As of December 31, 2019, estimated future development costs relating to our proved undeveloped reserves were $591.5 million, $615.6 million, and $458.1 million in 2020, 2021, and 2022, respectively.
Internal Controls Over Proved Reserves Estimates
Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to our corporate reserves group and is coordinated by our Corporate Engineering Manager, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below. Our Corporate Engineering Manager has approximately 12 years of experience in the energy industry and has been employed by the Company for 10 years. He holds a Bachelor of Science Degree in Petroleum Engineering from Montana Tech of the University of Montana and is a Registered Professional Petroleum Engineer in the states of Texas, Wyoming and Montana. He is also a member of the Society of Petroleum Engineers. Technical, geological, and engineering reviews of our assets are performed throughout the year by our regional staff. Data, obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. Our regional engineering technical staff do not report directly to our Corporate Engineering Manager; they report to either their respective regional technical managers or directly to the regional manager. This design is intended to promote objective and independent analysis within our regions in the proved reserves estimation process.
Third-party Reserves Audit
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over 70 years. Ryder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the proved reserve amounts of our audited properties determined by Ryder Scott are required, per our policy, to be within 10 percent of our proved reserve amounts for the total Company, as well as for each respective region. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is an Advising Senior Vice President who received a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. The 2019 Ryder Scott report concerning our reserves is included as Exhibit 99.1.
In addition to a third-party audit, our reserves are reviewed by our management with the Audit Committee of our Board of Directors. Our management, which includes our President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and Executive Vice President and Chief Operating Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives, apart from our management, from time to time to discuss processes and findings.
Production
The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties in which we held an interest during the periods presented. Realized prices presented below exclude the effects of derivative contract settlements. Also presented is a summary of related production expense on a per BOE basis.
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Net production volumes | | | | | |
| Oil (MMBbl) | 21.9 |
| | 18.8 |
| | 13.7 |
|
| Gas (Bcf) | 109.8 |
| | 103.2 |
| | 123.0 |
|
| NGLs (MMBbl) | 8.1 |
| | 7.9 |
| | 10.3 |
|
Equivalent (MMBOE) (1) | 48.3 |
| | 43.9 |
| | 44.5 |
|
Midland Basin net production volumes (2) | | | | | |
| Oil (MMBbl) | 20.5 |
| | 16.6 |
| | 8.5 |
|
| Gas (Bcf) | 34.4 |
| | 25.8 |
| | 14.7 |
|
| NGLs (MMBbl) | — |
| | — |
| | — |
|
Equivalent (MMBOE) (1) | 26.3 |
| | 20.9 |
| | 11.0 |
|
Eagle Ford shale net production volumes (2)(3) | | | | | |
| Oil (MMBbl) | 1.3 |
| | 1.2 |
| | 1.9 |
|
| Gas (Bcf) | 75.4 |
| | 76.1 |
| | 104.0 |
|
| NGLs (MMBbl) | 8.1 |
| | 7.9 |
| | 10.1 |
|
Equivalent (MMBOE) (1) | 21.9 |
| | 21.8 |
| | 29.3 |
|
| Realized price, before the effect of derivative settlements | | | | | |
| Oil (per Bbl) | $ | 54.10 |
| | $ | 56.80 |
| | $ | 47.88 |
|
| Gas (per Mcf) | $ | 2.39 |
| | $ | 3.43 |
| | $ | 3.00 |
|
| NGLs (per Bbl) | $ | 17.26 |
| | $ | 27.22 |
| | $ | 22.35 |
|
| Per BOE | $ | 32.84 |
| | $ | 37.27 |
| | $ | 28.20 |
|
| Production expense per BOE | | | | | |
| Lease operating expense | $ | 4.67 |
| | $ | 4.74 |
| | $ | 4.43 |
|
| Transportation costs | $ | 3.88 |
| | $ | 4.36 |
| | $ | 5.48 |
|
| Production taxes | $ | 1.35 |
| | $ | 1.52 |
| | $ | 1.18 |
|
| Ad valorem tax expense | $ | 0.48 |
| | $ | 0.48 |
| | $ | 0.34 |
|
| |
(1) | Amounts may not calculate due to rounding. |
| |
(2) | For each of the years ended December 31, 2019, 2018, and 2017, total estimated proved reserves attributed to our Midland Basin assets and our Eagle Ford shale assets exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis. |
| |
(3) | During the first quarter of 2017, we completed the divestiture of our outside-operated Eagle Ford shale assets. These assets represented approximately 1.5 MMBOE of net production on an equivalent basis for the year ended December 31, 2017. |
Productive Wells
As of December 31, 2019, we had working interests in 807 gross (758 net) productive oil wells and 519 gross (487 net) productive gas wells. Productive wells are exploratory, development, or extension wells that are producing, or are capable of commercial production of oil, gas, and/or NGLs. Productive wells may be temporarily shut-in. Multiple completions in the same wellbore are counted as one well. As of December 31, 2019, two of these wells had multiple completions. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil when it first commenced production, but such designation may not be indicative of current or future production composition.
Drilling and Completion Activity
All of our drilling and completion activities are conducted by independent contractors. We do not own any drilling or completion equipment. The following table summarizes the number of operated and outside-operated wells drilled and completed or recompleted on our properties in 2019, 2018, and 2017, excluding non-consented projects, active injector wells, salt water disposal wells, or wells in which we own only a royalty interest:
|
| | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Development wells | | | | | | | | | | | |
| Oil | 119 |
| | 107 |
| | 103 |
| | 92 |
| | 56 |
| | 46 |
|
| Gas | 27 |
| | 16 |
| | 39 |
| | 24 |
| | 38 |
| | 35 |
|
| Non-productive | 1 |
| | 1 |
| | — |
| | — |
| | 4 |
| | 3 |
|
| | 147 |
| | 124 |
| | 142 |
| | 116 |
| | 98 |
| | 84 |
|
| Exploratory wells | | | | | | | | | | | |
| Oil | 4 |
| | 4 |
| | 18 |
| | 14 |
| | 32 |
| | 29 |
|
| Gas | 4 |
| | 4 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Non-productive | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
|
| | 9 |
| | 9 |
| | 19 |
| | 15 |
| | 33 |
| | 29 |
|
| Total | 156 |
| | 133 |
| | 161 |
| | 131 |
| | 131 |
| | 113 |
|
A productive well is an exploratory, development, or extension well that is producing or is capable of commercial production of oil, gas, and/or NGLs. A non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development, or extension well that proves to be incapable of producing oil, gas, and/or NGLs in sufficient commercial quantities to justify completion, or upon completion, the economic operation of a well.
As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Our operations are also subjectrefers to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry hole, the reporting to the appropriate authority that may bethe well has been abandoned.
In addition to the wells drilled and completed in an area,2019 (included in the spacingtable above), we were actively participating in the drilling of 22 gross (20 net) wells and had 66 gross (63 net) drilled but not completed wells as of January 31, 2020. These drilled but not completed wells represent wells that were being completed or were waiting on completion as of January 31, 2020.
Acreage
The following table sets forth the unitization or poolingnumber of gross and net surface acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes that we held as of December 31, 2019. Undeveloped acreage includes leasehold interests containing proved undeveloped reserves.
|
| | | | | | | | | | | | | | | | | |
| | Developed Acres (1) | | Undeveloped Acres (2)(3) | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Midland Basin: | | | | | | | | | | | |
| RockStar | 67,113 |
| | 59,589 |
| | 4,966 |
| | 4,217 |
| | 72,079 |
| | 63,806 |
|
| Sweetie Peck | 17,007 |
| | 15,782 |
| | 2,835 |
| | 251 |
| | 19,842 |
| | 16,033 |
|
Midland Basin Total (4) | 84,120 |
| | 75,371 |
| | 7,801 |
| | 4,468 |
| | 91,921 |
| | 79,839 |
|
| Eagle Ford shale | 74,247 |
| | 71,296 |
| | 88,058 |
| | 87,631 |
| | 162,305 |
| | 158,927 |
|
Other (5) | 16,259 |
| | 11,363 |
| | 90,415 |
| | 25,599 |
| | 106,674 |
| | 36,962 |
|
| Total | 174,626 |
| | 158,030 |
| | 186,274 |
| | 117,698 |
| | 360,900 |
| | 275,728 |
|
| |
(1) | Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as developed acreage in the table above. |
| |
(2) | Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. |
| |
(3) | As of February 6, 2020, approximately 1,354, 184, and 155 net acres of undeveloped acreage are scheduled to expire by December 31, 2020, 2021, and 2022, respectively, if production is not established or we take no other action to extend the terms of the applicable leases. Certain of our Eagle Ford shale acreage is subject to lease consolidation agreements containing drilling, completion, and other obligations that we currently intend to satisfy. Failure to meet these obligations results in termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous development obligations required by individual leases are not met. |
| |
(4) | As of December 31, 2019, total Midland Basin acreage excludes approximately 1,940 net acres associated with drill-to-earn opportunities that we intend to pursue. |
| |
(5) | Includes other non-core acreage located in Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming. |
Delivery Commitments
As of December 31, 2019, we had gathering, processing, transportation throughput, and delivery commitments with various third-parties that require delivery of a minimum quantity of 24 MMBbl of oil and 424 Bcf of gas properties. In addition, state conservation laws sometimes establish maximum ratesthrough 2023, and 18 MMBbl of produced water through 2027. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. We expect to fulfill our delivery commitments from a combination of production from our existing productive wells, future development of our proved undeveloped reserves, and future development of resources not yet characterized as proved reserves. Under certain of our commitments, if we are unable to deliver the minimum quantity from our production, we may deliver production acquired from third-parties to satisfy our minimum volume commitments.
As of December 31, 2019, in the event that no additional volumes are delivered in accordance with these agreements, the aggregate undiscounted future deficiency payments would total $218.5 million. This amount does not include deficiency payment estimates associated with approximately 16.5 MMBbl of future oil delivery commitments where we cannot predict with accuracy the amount and timing of these payments, as such payments are dependent upon the price of oil in effect at the time of settlement.
As of the filing of this report, we do not expect to incur any material shortfalls with regard to these commitments.
Major Customers
We do not believe the loss of any single purchaser of our production would materially impact our operating results, as oil, gas, and NGLs are products with well-established markets and other viable purchaser options are available in our operating regions.
The following major customers and entities under common control accounted for 10 percent or more of our total oil, gas, and NGL production revenue for at least one of the periods presented:
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
Major customer #1 (1) | 18 | % | | 18 | % | | 6 | % |
Major customer #2 (1) | 14 | % | | 5 | % | | 1 | % |
Major customer #3 (1) | 13 | % | | 7 | % | | — | % |
Major customer #4 (1) | 9 | % | | 10 | % | | 10 | % |
Group #1 of entities under common control (2) | 13 | % | | 18 | % | | 17 | % |
Group #2 of entities under common control (2) | 11 | % | | 12 | % | | 8 | % |
| |
(1) | These major customers are purchasers of a portion of our production from our Midland Basin assets. |
| |
(2) | In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of our total oil, gas, and NGL production revenue. |
Employees and Office Space
As of February 6, 2020, we had 530 full-time employees. This is a 13 percent decrease from the 611 full-time employees that we reported as of February 7, 2019. None of our employees are subject to a collective bargaining agreement.
The following table summarizes the approximate square footage of office space leased by us, as of December 31, 2019, including our corporate headquarters and regional offices:
|
| | | |
| | Approximate Square Footage Leased |
| Corporate | | 107,000 |
|
| Midland Basin | | 59,000 |
|
| South Texas | | 62,000 |
|
| Total | | 228,000 |
|
In addition to the leased office space summarized in the table above, as of December 31, 2019, we owned approximately 12,000 square feet of office space in South Texas.
Title to Properties
Substantially all of our oil and gas wells, generally limit or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Some of our operationsproducing assets are conducted on federal landsheld pursuant to oil and gas leases administered byfrom third-party mineral owners. We obtain title opinions prior to commencing initial drilling operations on the Bureauproperties we operate. We have obtained title opinions or have conducted other title review on substantially all of Land Management (“BLM”). These leases contain relatively standardized termsour producing properties and require compliance with detailed regulations and orders thatbelieve we have satisfactory title to such properties. Most of our producing properties are subject to change. In addition to permits required frommortgages securing indebtedness under our Credit Agreement, royalty and overriding royalty interests, liens for current taxes, and other regulatory agencies, lessees must obtain a permit fromordinary course burdens that we believe do not materially interfere with the BLMdevelopment of such properties. We typically perform title investigation in accordance with standards generally accepted in the oil and gas industry before drillingacquiring developed and must comply with regulations governing, among other things, engineeringundeveloped leasehold acreage.
Seasonality
The price of crude oil is primarily driven by global socioeconomic factors and construction specificationsis less affected by seasonal fluctuations; however, demand for production facilities, safety procedures,energy is generally higher in the valuationwinter and the summer driving season. The demand and price for gas frequently increases during winter months and decreases during summer months. To lessen the impact of productionseasonal gas demand and payment of royalties, the removal ofprice fluctuations, pipelines, utilities, local distribution companies, and industrial users regularly utilize gas storage facilities and forward purchase some of their anticipated winter requirements during the postingsummer. However, increased summertime demand for electricity can divert gas that is traditionally placed into storage which, in turn, may increase the typical winter seasonal price. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.
Certain of bondsour drilling, completion, and other operations are also subject to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminateseasonal limitations. Seasonal weather conditions, government regulations, and lease stipulations adversely affect our operations on federal leases.
Our sales of natural gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of natural gasability to conduct drilling activities in interstate commerce. FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the midstream and transportation segmentssome of the areas where we operate. Please refer to Risk Factors - Risks Related to Our Businessbelow for additional discussion.
Competition
The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and thus can indirectly affect the sales pricesgas properties. We believe our acreage positions provide a foundation for development activities that we receive for natural gas production.
Environmental, Healthexpect to fuel our future growth. Our competitive position also depends on our geological, geophysical, and Safety Matters
General. Our operations are subject to stringent and complex federal, state, tribal, and local laws and regulations governing protection of the environment and worker health and safetyengineering expertise, as well as our financial resources. We believe the dischargelocation of materials intoour acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the environment. These lawsexperience and regulations may, among other things:
requireknowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which in some cases have larger technical teams and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, of various permits before drilling commences;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and
require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.
These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes may result in more stringent permitting, waste handling, disposal, and cleanup requirements for the oil and natural gas industry and could have a significant impact on our operating costs.
The following is a summary of some of the existing laws, rules and regulations to which our business is subject.
Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil and gas reserves, but also have gathering, processing or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certainrefining operations, market refined products, provide, dispose of and transport fresh and produced water, own drilling rigs or production equipment, or generate electricity.
We also compete with other oil and natural gas explorationcompanies in securing drilling rigs and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manageother equipment and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsibleservices necessary for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, pay fines, remediate contaminated property, or perform remedial operations to prevent future contamination.
Water discharges. The federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of Engineers or analogous state agencies. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.
Air emissions. The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and the demand for oil and gas. See Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural gas, and NGLs. In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products.
Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts on protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on these species. It is also possible that a federal or state agency could order a complete halt to activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.
National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Departmentmaintenance of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment to determine the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities,wells, as well as proposed
explorationfor the gathering, transporting, and development plans, on federal lands require governmental permits subjectprocessing of oil, gas, NGLs and water. Consequently, we may face shortages, delays, or increased costs in securing these services from time to the requirements of NEPA. This process has the potential to delay development of some of our oil and natural gas projects.
OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes.time. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe we are in substantial compliance with the applicable requirements of OSHA and comparable laws.
Hydraulic fracturing. Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water sources.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic fracturing techniques, which could potentially cause a decrease inindustry also faces competition from alternative fuel sources, including renewable energy sources such as solar and wind-generated energy, and other fossil fuels such as coal. Competitive conditions may be affected by future energy, climate-related, financial, or other policies, legislation, and regulations.
In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the completion of new oil and gas wells, increased compliance costs,industry, the need to attract and delays, allretain talented people has grown at a time when the availability of which could adversely affectindividuals with these skills is becoming more limited due to the evolving demographics of our financial position, results of operations and cash flows. As new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
We believe it is reasonably likely that the trend in local and state environmental legislation and regulation will continue toward stricter standards, while the trend in federal environmental legislation and regulation faces an uncertain future under the Trump administration. While we believe we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the future.
Environmental, Health and Safety Initiatives. industry. We are committednot insulated from competition for quality people, and we must compete effectively in order to conducting our business in a manner that protects the environment and the health and safety of our employees, contractors and the public. We set annual goals for our environmental, health and safety program focused on reducing the number of safety related incidents that occur and the number and impact of spills of produced fluids. We also periodically conduct regulatory compliance audits of our operations to ensure our compliance with all regulations and provide appropriate training for our employees. Reducing air emissions as a result of leaks, venting, or flaring of natural gas during operations has become a major focus area for regulatory efforts and for our compliance efforts. While flaring is sometimes necessary, releases of natural gas to the environment and flaring is an economic waste and reducing these volumes is a priority for us. To avoid flaring where possible, we restrict testing periods and make every effort to ensure that our production is connected to gas pipeline infrastructure as quickly as possible after well completions. We have cooperated with other producers in North Dakota in the ongoing development of recommendations to reduce the amount of flaring that is occurring there as a result of area wide infrastructure limitations that are beyond our control. Another focus for our environmental effort has been reduction of water use through recycling of flowback water in south Texas for use as frac fluid. We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance. Such expenditures are included within our overall capital budget and are not separately itemized.
be successful.
Cautionary Information about Forward-Looking Statements
This Annual Report on Form 10-K (“Form 10-K”) contains “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 facts, included in this Form 10-Kreport that address activities, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “intend,” “pending,” “plan,” “potential,” “project,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this Form 10-K,report, and include statements about such matters as:
the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”);
our outlook on future crude oil, natural gas, and NGLnatural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this document) prices, well costs, service costs, lease operating costs, and servicegeneral and administrative costs;
the drilling of wells and other exploration and development activities, the ability to obtain permits and governmental approvals, and plans as well as by us, our joint development partners, and/or other third-party operators;
possible or expected acquisitions or divestitures;
and divestitures, including the possible divestiture or farm-down of, or joint venture relating to, certain properties;
provedoil, gas, and NGL reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;
future oil, gas, and NGL production estimates;estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;
cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;
plans, objectives, expectations and intentions; and
| |
| • | other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report. |
other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in Part II, Item 7 of this Form 10-K.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Some of these risks are described in the Risk Factors section of this Form 10-K, and include such factors as:
the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;
weakness in economic conditions and uncertainty in financial markets;
our ability to replace reserves in order to sustain production;
our ability to raise the substantial amount of capital required to develop and/or replace our reserves;
our ability to compete against competitors that have greater financial, technical, and human resources;
our ability to attract and retain key personnel;
the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;
the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;
the possibility that exploration and development drilling may not result in commercially producible reserves;
our limited control over activities on outside-operated properties;
our reliance on the skill and expertise of third-party service providers on our operated properties;
the possibility that title to properties in which we claim an interest may be defective;
our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;
the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;
the uncertainties associated with enhanced recovery methods;
our commodity derivative contracts may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;
the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;
our ability to deliver required quantities of crude oil, natural gas, natural gas liquids, or water to contractual counterparties;
price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;
the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;
the possibility that covenants in our Credit Agreement or the indentures governing the Senior Notes and Senior Convertible Notes may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions or lead to the accelerated payment of our debt;
operating and environmental risks and hazards that could result in substantial losses;
the impact of seasonal weather conditions and lease stipulations on our ability to conduct drilling activities;
our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;
complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;
the availability and capacity of gathering, transportation, processing, and/or refining facilities;
our ability to sell and/or receive market prices for our oil, gas, and NGLs;
new technologies may cause our current explorationfinancial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in Part I, Item 1A, Risk Factors - Risks Related to Our Business below and drilling methods to become obsolete;
the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and
litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.
We caution you that forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or impliedelsewhere in the forward-looking statements.this report. The forward-looking statements in this report speak as of the filing date of this report. Although, we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.
Available Information
Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also make available through our website our Corporate Governance Guidelines, Code of Business Conduct and Conflict of Interest Policy, Financial Code of Ethics, and the Charters of the Audit, Compensation, Executive, and Nominating and Corporate Governance Committees of our Board of Directors. Information on our website is not incorporated by reference into this report and should not be considered part of this document.
Glossary of Oil and Gas Terms
The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the SEC’sSecurities and Exchange Commission’s (“SEC”) website at www.sec.gov.
Ad valorem tax. A tax based on the value of real estate or personal property.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs, water, or other liquid hydrocarbons.
BBtu. One billion British thermal units.
Bcf.BillionOne billion cubic feet, used in reference to natural gas.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs.
BTU.Btu. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Developed acreage.The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (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.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil, natural gas, and/or NGLs in commercial quantities.
Exploratory well.A well drilled to find and produce oila new field or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir beyond its known horizon.reservoir.
Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and natural gas) rights.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Finding and development cost. Expressed in dollars per BOE. Finding and development cost metrics provide information as to the cost of adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as by investors and analysts. The information used to calculate these metrics is included in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report. It should be noted that finding and development cost metrics have limitations. For example, exploration efforts related to a particular set of proved reserve additions may extend over several years. As a result, the exploration costs incurred in earlier periods are not included in the amount of exploration costs incurred during the period in which that set of proved reserves is added. In addition, consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Since the additional development costs that will need to be incurred in the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurred during the period in which those reserves were added, those development costs in future periods will be reflected in the costs associated with adding a different set of reserves.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Frac spread. Hydraulic fracturing requires custom-designed and purpose-built equipment. A “frac spread” is the equipment necessary to carry out a fracturing job.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.
Lease operating expenses. The expenses incurred in the lifting of crude oil, natural gas, and/or associated liquidsNGLs from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.
MBbl. One thousand barrels of crude oil, NGLs, water, or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet, used in reference to natural gas.
MMBbl. One million barrels of oil, NGLs, water, or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet, used in reference to natural gas.
Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.
NGLs.The combination of ethane, propane, isobutane, normal butane, and natural gasolinesgasoline that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
NYMEX WTI. New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for crude oil.
NYMEX Henry Hub. New York Mercantile Exchange Henry Hub, a common industry benchmark price for natural gas.
OPIS. Oil Price Information Service, a common industry benchmark for NGL pricing at Mont Belvieu, Texas.
PV-10 (Non-GAAP). PV-10 is a non-GAAP measure. The present value of estimated future revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.
Productive well. A well that is producing crude oil, natural gas, and/or NGLs or that is capable of commercial production of those products.
Proved reserves. Those quantities of oil, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Recompletion. The completion of an existing wellbore in a formation other than that in which the well has previously been completed.
Reserve life index. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.
Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual production volumes and grow its reserves, and provide information related to how successful a company is at growing its proved reserve base. These are believed to be useful non-GAAP measures that are widely utilized within the exploration and production industry, as well as by investors and analysts. They are easily calculable metrics, and the information used to calculate these metrics is included in the Supplemental Oil and Gas Information section of Part II, Item 8 of this report. It should be noted that reserve replacement metrics have limitations. They are limited because they typically vary widely based on the extent and timing of new discoveries and property acquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, because the metrics do not embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil, natural gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resource play. A term used to describe an accumulation of crude oil, natural gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has lower expected geological risk.
Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil, natural gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.
Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of crude oil, natural gas, and NGL production free of costs of exploration, development, and production operations.
Seismic. Thesending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
Standardized measure of discounted future net cash flows. The discounted future net cash flows relatingrelated to estimated proved reserves based on prices used in estimating the reserves, year-endyear end costs, and statutory tax rates, andat a 10 percent annual discount rate. The information for this calculation is included in Supplemental Oil and Gas Information (unaudited) located in Part II, Item 8 of this report.
Track record. Current year conversions of proved undeveloped reserves to proved developed reserves, divided by beginning of the year proved undeveloped reserves.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, natural gas, and associated liquidsNGLs regardless of whether such acreage contains estimated net proved reserves.
Undeveloped reserves. 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. The applicable SEC definition of undeveloped reserves provides that 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.
Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs.
PART I
When we use the terms “SM Energy,” the “Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business in the Glossary of Oil and Gas Terms section of this report. Throughout this document we make statements and projections that address future expectations, possibilities, or events, all of which may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this report for an explanation of these types of statements and the associated risks and uncertainties.
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of Texas. SM Energy was founded in 1908, incorporated in Delaware in 1915, and our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”
Our principal office is located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Strategy
At SM Energy, our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision for the Company is to sustainably grow value for all of our stakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top tier assets. Our current energy project development portfolio is focused on oil and gas producing properties in the state of Texas.
Significant Developments in 2019
Strategic Transformation. During 2019, we completed our strategic transformation, which commenced in 2016 through a series of asset acquisitions and divestitures. For the fourth quarter of 2019, we passed an important milestone by achieving a positive difference between our net cash provided by operating activities and our net cash used in investing activities. Our operational execution in 2019 was outstanding, achieving our objectives in important industry metrics, including key top-quartile benchmarks for environmental, health, and safety performance. We were also successful in proving up additional investment opportunities on our existing acreage positions.
Production. Our average daily production in 2019 consisted of 59.9 MBbl of oil, 300.8 MMcf of gas, and 22.2 MBbl of NGLs, for an average net daily equivalent production rate of 132.3 MBOE, which represented a 10 percent increase compared with 2018. This increase was primarily driven by a 25 percent increase in production volumes from our Midland Basin assets as a result of strong well performance, increased drilling and completion efficiencies, improved completion designs, and longer laterals. We completed more lateral feet in 2019 compared with 2018, driving continued increases in volumes at a lower average drilling and completion cost. On a retained asset basis, our production volumes increased 13 percent in 2019. As a result of the above, oil production revenue was approximately 75 percent of total production revenue for the year ended December 31, 2019, compared with 65 percent and 52 percent for the years ended December 31, 2018 and 2017, respectively. Please refer to Areas of Operationbelow for additional discussion.
Reserves and Capital Investment. Our estimated proved reserves decreased eight percent to 462.0 MMBOE at December 31, 2019, from 503.4 MMBOE at December 31, 2018. Reserve additions from discoveries, extensions, and infills totaled 98.4 MMBOE and were a result of our successful development programs, completion optimizations that resulted in improved well performance, and development plan improvements that we believe will enhance inventory value. The 2019 reserve additions were offset by 2019 production volumes of 48.3 MMBOE and by downward revisions of 94.7 MMBOE, which resulted primarily from the impact of lower commodity prices. Our proved reserve life index decreased to 9.6 years as of December 31, 2019, compared with 11.5 years as of December 31, 2018. Costs incurred for development and exploration activities, excluding acquisitions, decreased 23 percent from the prior year to $1.0 billion in 2019. Please refer to Areas of Operationand Reservesbelow, and to Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report for additional discussion.
Net Cash Provided by Operating Activities. Net cash provided by operating activities was $823.6 million for the year ended December 31, 2019, compared with $720.6 million for the year ended December 31, 2018, which was an increase of 14 percent year-over-year. Oil, gas, and NGL production revenues decreased for the year ended December 31, 2019, compared with 2018, as the impact from higher production volumes was offset by lower commodity prices. However, the impact of lower commodity prices in 2019 was offset by a net derivative cash settlement gain of $39.2 million for the year ended December 31, 2019, compared to a net derivative cash settlement loss of $135.8 million for 2018. Please refer to Analysis of Cash Flow Changes Between 2019 and 2018 and Between
2018 and 2017 in Overview of Liquidity and Capital Resourcesin Part II, Item 7, and to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Outlook
Our business outlook for the next several years is a continuation of our trajectory of improving operating margins and cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics. Our total capital program in 2020, is budgeted to be between $825.0 million and $850.0 million, and is expected to be approximately 20% lower compared with 2019, in large part due to significant cost reductions and efficiencies that were achieved in 2019. Our 2020 program will be focused on highly economic oil development projects in both our Midland Basin and South Texas assets. We expect total production volumes in 2020 to decrease slightly compared with 2019 as expected continued growth in our oil production volumes will not completely offset expected decreases in gas and NGL production volumes.
Sustainability is a key focus of our plans, in terms of positioning ourselves financially to participate in future energy investment opportunities, and executing our strategy of being a premier operator with high standards for corporate responsibility. We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive difference in the communities where we live and work; and transparency in reporting on our progress in these areas.
Please refer to Overview of Liquidity and Capital Resources in Part II, Item 7 of this report for discussion of how we expect to fund our 2020 capital program.
Areas of Operation
Our 2019 operations were concentrated in the Midland Basin and South Texas, as further described below. The following table summarizes estimated proved reserves, production, and costs incurred in oil and gas producing activities (“costs incurred”) for the year ended December 31, 2019, for these areas:
|
| | | | | | | | | | | |
| Midland Basin | | South Texas | | Total (1) |
| Proved reserves | | | | | |
| Oil (MMBbl) | 167.5 |
| | 16.6 |
| | 184.1 |
|
| Gas (Bcf) | 398.8 |
| | 824.4 |
| | 1,223.2 |
|
| NGLs (MMBbl) | 0.1 |
| | 73.9 |
| | 74.0 |
|
MMBOE (1) | 234.1 |
| | 227.8 |
| | 462.0 |
|
| Relative percentage | 51 | % | | 49 | % | | 100 | % |
| Proved developed % | 49 | % | | 58 | % | | 53 | % |
| Production | | | | | |
| Oil (MMBbl) | 20.5 |
| | 1.3 |
| | 21.9 |
|
| Gas (Bcf) | 34.4 |
| | 75.4 |
| | 109.8 |
|
| NGLs (MMBbl) | — |
| | 8.1 |
| | 8.1 |
|
MMBOE (1) | 26.3 |
| | 22.0 |
| | 48.3 |
|
Avg. daily equivalents (MBOE/d) (1) | 72.0 |
| | 60.3 |
| | 132.3 |
|
| Relative percentage | 54 | % | | 46 | % | | 100 | % |
Costs incurred (in millions) (2) (3) | $ | 859.6 |
| | $ | 160.9 |
| | $ | 1,040.2 |
|
| |
(1) | Amounts may not calculate due to rounding. |
| |
(2) | Regional costs incurred do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activities that are excluded from this regional table. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report. |
| |
(3) | Costs incurred for 2019 included $11.3 million related to acquisitions of primarily unproved oil and gas properties in the Midland Basin. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report. |
Excluding acquisition activity, costs incurred decreased in 2019 by 23 percent compared with 2018 primarily due to increased operational efficiencies and decreased drilling, completion crew, and sand costs incurred in developing our Midland Basin assets. Total estimated proved reserves at year end 2019 decreased eight percent from 2018. Production increased 10 percent on an equivalent basis for the year ended December 31, 2019, compared with 2018, and increased 13 percent on a retained assets basis.
Midland Basin. Our Midland Basin assets are located within the Permian Basin in Western Texas and are comprised of approximately 80,000 net acres (“Midland Basin”). In 2019, we focused on continuing to delineate, develop, and expand our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
In 2019, we incurred $859.6 million of costs and averaged six drilling rigs and three completion crews. The majority of our Midland Basin capital was deployed on projects targeting the Lower Spraberry and Wolfcamp A and B intervals on our RockStar assets in Howard and Martin Counties, Texas and Sweetie Peck assets in Upton and Midland Counties, Texas. We completed 123 gross (111 net) wells and full-year production increased 25 percent year-over-year to 26.3 MMBOE for 2019. As of December 31, 2019, there were 51 gross (48 net) wells that had been drilled but not completed in our Midland Basin program. Estimated proved reserves increased nine percent to 234.1 MMBOE at year end 2019, from 214.3 MMBOE at year end 2018. This increase was driven by additions of 58.9 MMBOE from discoveries, extensions and infill, and acquisitions, partially offset by 12.6 MMBOE of downward revisions from price, performance, and aged proved undeveloped reserves.
South Texas. Our South Texas assets are comprised of approximately 158,900 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on developing the Eagle Ford shale formation and delineating the Austin Chalk formation. Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations covers a significant portion of the western Eagle Ford shale and Maverick Basin Austin Chalk (“Eagle Ford shale”) and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.
In 2019, we incurred $160.9 million of costs and averaged one drilling rig and one completion crew. We completed 31 gross (20 net) wells during 2019, and full-year regional production increased one percent year-over-year to 22.0 MMBOE for 2019. As of December 31, 2019, there were 21 gross (21 net) wells that had been drilled but not completed in our South Texas program.
Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to our joint development agreement. The agreement provided that the third party carried substantially all drilling and completion costs and receives a majority of the working and revenue interest in these wells until certain payout thresholds are reached. This arrangement allowed us to leverage third-party capital to prove up the value of our Eagle Ford North area, while also allowing us to test cutting edge technology, capture additional technical data, satisfy certain lease obligations, and potentially expand economic drilling inventory in the future. All wells subject to this agreement were drilled and completed as of December 31, 2019.
During 2019, we added 43.0 MMBOE of estimated proved reserves, offset by downward revisions of 82.1 MMBOE, of which 68.5 MMBOE resulted from decreased commodity pricing and 10.3 MMBOE resulted from performance revisions. As a result, estimated proved reserves decreased 21 percent to 227.8 MMBOE at year end 2019, from 289.1 MMBOE at year end 2018.
Reserves
Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. The following table presents the standardized measure of discounted future net cash flows and pre-tax PV-10 (“PV-10”). PV-10 is a non-GAAP financial measure, and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither the standardized measure of discounted future net cash flows nor PV-10 represents the fair market value of our oil and gas properties. We and others in the oil and gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held without regard to the specific tax characteristics of such entities. Please refer to the Glossary of Oil and Gas Terms section of this report for additional information regarding these measures and refer to the reconciliation of the standardized measure of discounted future net cash flows to PV-10 set forth below. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – Risks Related to Our Businessbelow.
Our ability to replace production with new oil and gas reserves is critical to the future success of our business. Please refer to the reserve life index term in the Glossary of Oil and Gas Terms section of this report for information describing how this metric is calculated.
The following table summarizes estimated proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP), the prices used in the calculation of proved reserves estimates, and reserve life index as of December 31, 2019, 2018, and 2017:
|
| | | | | | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 | | 2017 |
| Reserve data: | | | | | |
| Proved developed | | | | | |
| Oil (MMBbl) | 85.0 |
| | 68.2 |
| | 58.6 |
|
| Gas (Bcf) | 712.1 |
| | 699.1 |
| | 642.9 |
|
| NGLs (MMBbl) | 43.4 |
| | 60.1 |
| | 49.0 |
|
MMBOE (1) | 247.0 |
| | 244.8 |
| | 214.7 |
|
| Proved undeveloped | | | | | |
| Oil (MMBbl) | 99.1 |
| | 107.6 |
| | 99.6 |
|
| Gas (Bcf) | 511.1 |
| | 622.7 |
| | 637.2 |
|
| NGLs (MMBbl) | 30.6 |
| | 47.2 |
| | 47.6 |
|
MMBOE (1) | 214.9 |
| | 258.6 |
| | 253.4 |
|
Total proved (1) | | | | | |
| Oil (MMBbl) | 184.1 |
| | 175.7 |
| | 158.2 |
|
Gas (Bcf) (2) | 1,223.2 |
| | 1,321.8 |
| | 1,280.1 |
|
| NGLs (MMBbl) | 74.0 |
| | 107.4 |
| | 96.5 |
|
| MMBOE | 462.0 |
| | 503.4 |
| | 468.1 |
|
| Proved developed reserves % | 53 | % | | 49 | % | | 46 | % |
| Proved undeveloped reserves % | 47 | % | | 51 | % | | 54 | % |
| | | | | | |
| Reserve data (in millions): | | | | | |
| Standardized measure of discounted future net cash flows (GAAP) | $ | 4,104.0 |
| | $ | 4,654.4 |
| | $ | 3,024.1 |
|
| PV-10 (non-GAAP): | | | | | |
| Proved developed PV-10 | $ | 2,830.4 |
| | $ | 3,084.2 |
| | $ | 1,984.2 |
|
| Proved undeveloped PV-10 | 1,532.4 |
| | 2,020.1 |
| | 1,072.3 |
|
| Total proved PV-10 (non-GAAP) | $ | 4,362.8 |
| | $ | 5,104.3 |
| | $ | 3,056.5 |
|
| | | | | | |
12-month trailing average prices (3) | | | | | |
| Oil (per Bbl) | $ | 55.69 |
| | $ | 65.56 |
| | $ | 51.34 |
|
| Gas (per MMBtu) | $ | 2.58 |
| | $ | 3.10 |
| | $ | 3.00 |
|
| NGLs (per Bbl) | $ | 22.68 |
| | $ | 33.45 |
| | $ | 27.69 |
|
| | | | | | |
| Reserve life index (years) | 9.6 |
| | 11.5 |
| | 10.5 |
|
| |
(1) | Amounts may not calculate due to rounding. |
| |
(2) | For the years ended December 31, 2019, 2018, and 2017, proved gas reserves contained 44.9 Bcf, 59.1 Bcf, and 48.1 Bcf of gas, respectively, that we expect to produce and use as a field equipment fuel source (primarily to power compressors). |
| |
(3) | The prices used in the calculation of proved reserve estimates reflect the 12-month average of the first-day-of-the-month prices in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves. |
The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 (non-GAAP) of total estimated proved reserves. Please refer to the Glossary of Oil and Gas Termssection of this report forthe definitions of standardized measure of discounted future net cash flows and PV-10.
|
| | | | | | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Standardized measure of discounted future net cash flows (GAAP) | $ | 4,104.0 |
| | $ | 4,654.4 |
| | $ | 3,024.1 |
|
| Add: 10 percent annual discount, net of income taxes | 2,955.3 |
| | 3,847.1 |
| | 2,573.2 |
|
| Add: future undiscounted income taxes | 579.8 |
| | 1,012.2 |
| | 205.7 |
|
| Pre-tax undiscounted future net cash flows | 7,639.1 |
| | 9,513.7 |
| | 5,803.0 |
|
| Less: 10 percent annual discount without tax effect | (3,276.3 | ) | | (4,409.4 | ) | | (2,746.5 | ) |
| PV-10 (non-GAAP) | $ | 4,362.8 |
| | $ | 5,104.3 |
| | $ | 3,056.5 |
|
Proved Undeveloped Reserves
Proved undeveloped reserves include those reserves that are expected to be recovered from future wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2019, we did not have any proved undeveloped reserves that had been on our books in excess of five years, and none of our proved undeveloped reserves were on acreage expected to expire or on acreage that was not expected to be held through renewal before the targeted completion date.
For proved undeveloped locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic and engineering technology when booking estimated proved undeveloped reserves. Of the 214.9 MMBOE of total proved undeveloped reserves as of December 31, 2019, approximately 60.1 MMBOE of proved undeveloped reserves in the Midland Basin and 68.7 MMBOE of proved undeveloped reserves in our South Texas position were offset by more than one development spacing area from the nearest developed producing location. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected) and petrophysical analysis of that log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to development spacing areas that are immediately adjacent to developed spacing areas.
As of December 31, 2019, estimated proved undeveloped reserves decreased 43.7 MMBOE, or 17 percent compared with December 31, 2018. The following table provides a reconciliation of our proved undeveloped reserves for the year ended December 31, 2019:
|
| | |
| Total (MMBOE) |
| Total proved undeveloped reserves: | |
| Beginning of year | 258.6 |
|
| Revisions of previous estimates | (47.6 | ) |
| Additions from discoveries, extensions, and infill | 78.5 |
|
| Purchases of minerals in place | 1.9 |
|
| Removed for five-year rule | (9.8 | ) |
| Conversions to proved developed | (66.7 | ) |
| End of year | 214.9 |
|
Revisions of previous estimates. Revisions of previous estimates includes a downward pricing revision of 42.3 MMBOE from our South Texas program as a result of decreased gas and NGL prices. In addition, we had downward performance revisions of 6.0 MMBOE in our Midland Basin program as we updated certain assumptions based on future well spacing.
Additions from discoveries, extensions, and infill. We added 40.8 MMBOE and 30.4 MMBOE of infill estimated proved undeveloped reserves in our Midland Basin and South Texas assets, respectively, in 2019. We added an additional 3.1 MMBOE and 4.1 MMBOE of estimated proved undeveloped reserves in the Midland Basin and South Texas, respectively, through various extensions and discoveries. The majority of additions in our Midland Basin and South Texas programs resulted from future development projects identified by our on-going development and portfolio optimization activities.
Removed for five-year rule. As a result of our testing and delineation efforts in 2019, we revised certain aspects of our future development plans to focus on maximizing returns and the value of our assets. As a result, we removed 9.8 MMBOE of estimated proved undeveloped reserves and reclassified these locations to unproved reserve categories. The reclassified locations were generally replaced by locations with higher quality proved undeveloped reserves, which are reflected as additions from discoveries, extensions, and infill.
Conversions to proved developed. Our 2019 conversion rate was 26 percent. During 2019, we incurred $686.3 million on projects with reserves booked as proved undeveloped at the end of 2018, of which $611.1 million was spent on converting proved undeveloped reserves to proved developed reserves by December 31, 2019. At December 31, 2019, drilled but not completed wells represented 26.8 MMBOE of total estimated proved undeveloped reserves. We expect to incur $182.0 million of capital expenditures in completing these drilled but not completed wells, and we expect all estimated proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as proved undeveloped reserves.
As of December 31, 2019, estimated future development costs relating to our proved undeveloped reserves were $591.5 million, $615.6 million, and $458.1 million in 2020, 2021, and 2022, respectively.
Internal Controls Over Proved Reserves Estimates
Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to our corporate reserves group and is coordinated by our Corporate Engineering Manager, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below. Our Corporate Engineering Manager has approximately 12 years of experience in the energy industry and has been employed by the Company for 10 years. He holds a Bachelor of Science Degree in Petroleum Engineering from Montana Tech of the University of Montana and is a Registered Professional Petroleum Engineer in the states of Texas, Wyoming and Montana. He is also a member of the Society of Petroleum Engineers. Technical, geological, and engineering reviews of our assets are performed throughout the year by our regional staff. Data, obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. Our regional engineering technical staff do not report directly to our Corporate Engineering Manager; they report to either their respective regional technical managers or directly to the regional manager. This design is intended to promote objective and independent analysis within our regions in the proved reserves estimation process.
Third-party Reserves Audit
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over 70 years. Ryder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the proved reserve amounts of our audited properties determined by Ryder Scott are required, per our policy, to be within 10 percent of our proved reserve amounts for the total Company, as well as for each respective region. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is an Advising Senior Vice President who received a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. The 2019 Ryder Scott report concerning our reserves is included as Exhibit 99.1.
In addition to a third-party audit, our reserves are reviewed by our management with the Audit Committee of our Board of Directors. Our management, which includes our President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and Executive Vice President and Chief Operating Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives, apart from our management, from time to time to discuss processes and findings.
Production
The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties in which we held an interest during the periods presented. Realized prices presented below exclude the effects of derivative contract settlements. Also presented is a summary of related production expense on a per BOE basis.
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Net production volumes | | | | | |
| Oil (MMBbl) | 21.9 |
| | 18.8 |
| | 13.7 |
|
| Gas (Bcf) | 109.8 |
| | 103.2 |
| | 123.0 |
|
| NGLs (MMBbl) | 8.1 |
| | 7.9 |
| | 10.3 |
|
Equivalent (MMBOE) (1) | 48.3 |
| | 43.9 |
| | 44.5 |
|
Midland Basin net production volumes (2) | | | | | |
| Oil (MMBbl) | 20.5 |
| | 16.6 |
| | 8.5 |
|
| Gas (Bcf) | 34.4 |
| | 25.8 |
| | 14.7 |
|
| NGLs (MMBbl) | — |
| | — |
| | — |
|
Equivalent (MMBOE) (1) | 26.3 |
| | 20.9 |
| | 11.0 |
|
Eagle Ford shale net production volumes (2)(3) | | | | | |
| Oil (MMBbl) | 1.3 |
| | 1.2 |
| | 1.9 |
|
| Gas (Bcf) | 75.4 |
| | 76.1 |
| | 104.0 |
|
| NGLs (MMBbl) | 8.1 |
| | 7.9 |
| | 10.1 |
|
Equivalent (MMBOE) (1) | 21.9 |
| | 21.8 |
| | 29.3 |
|
| Realized price, before the effect of derivative settlements | | | | | |
| Oil (per Bbl) | $ | 54.10 |
| | $ | 56.80 |
| | $ | 47.88 |
|
| Gas (per Mcf) | $ | 2.39 |
| | $ | 3.43 |
| | $ | 3.00 |
|
| NGLs (per Bbl) | $ | 17.26 |
| | $ | 27.22 |
| | $ | 22.35 |
|
| Per BOE | $ | 32.84 |
| | $ | 37.27 |
| | $ | 28.20 |
|
| Production expense per BOE | | | | | |
| Lease operating expense | $ | 4.67 |
| | $ | 4.74 |
| | $ | 4.43 |
|
| Transportation costs | $ | 3.88 |
| | $ | 4.36 |
| | $ | 5.48 |
|
| Production taxes | $ | 1.35 |
| | $ | 1.52 |
| | $ | 1.18 |
|
| Ad valorem tax expense | $ | 0.48 |
| | $ | 0.48 |
| | $ | 0.34 |
|
| |
(1) | Amounts may not calculate due to rounding. |
| |
(2) | For each of the years ended December 31, 2019, 2018, and 2017, total estimated proved reserves attributed to our Midland Basin assets and our Eagle Ford shale assets exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis. |
| |
(3) | During the first quarter of 2017, we completed the divestiture of our outside-operated Eagle Ford shale assets. These assets represented approximately 1.5 MMBOE of net production on an equivalent basis for the year ended December 31, 2017. |
Productive Wells
As of December 31, 2019, we had working interests in 807 gross (758 net) productive oil wells and 519 gross (487 net) productive gas wells. Productive wells are exploratory, development, or extension wells that are producing, or are capable of commercial production of oil, gas, and/or NGLs. Productive wells may be temporarily shut-in. Multiple completions in the same wellbore are counted as one well. As of December 31, 2019, two of these wells had multiple completions. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil when it first commenced production, but such designation may not be indicative of current or future production composition.
Drilling and Completion Activity
All of our drilling and completion activities are conducted by independent contractors. We do not own any drilling or completion equipment. The following table summarizes the number of operated and outside-operated wells drilled and completed or recompleted on our properties in 2019, 2018, and 2017, excluding non-consented projects, active injector wells, salt water disposal wells, or wells in which we own only a royalty interest:
|
| | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Development wells | | | | | | | | | | | |
| Oil | 119 |
| | 107 |
| | 103 |
| | 92 |
| | 56 |
| | 46 |
|
| Gas | 27 |
| | 16 |
| | 39 |
| | 24 |
| | 38 |
| | 35 |
|
| Non-productive | 1 |
| | 1 |
| | — |
| | — |
| | 4 |
| | 3 |
|
| | 147 |
| | 124 |
| | 142 |
| | 116 |
| | 98 |
| | 84 |
|
| Exploratory wells | | | | | | | | | | | |
| Oil | 4 |
| | 4 |
| | 18 |
| | 14 |
| | 32 |
| | 29 |
|
| Gas | 4 |
| | 4 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Non-productive | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
|
| | 9 |
| | 9 |
| | 19 |
| | 15 |
| | 33 |
| | 29 |
|
| Total | 156 |
| | 133 |
| | 161 |
| | 131 |
| | 131 |
| | 113 |
|
A productive well is an exploratory, development, or extension well that is producing or is capable of commercial production of oil, gas, and/or NGLs. A non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development, or extension well that proves to be incapable of producing oil, gas, and/or NGLs in sufficient commercial quantities to justify completion, or upon completion, the economic operation of a well.
As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry hole, the reporting to the appropriate authority that the well has been abandoned.
In addition to the wells drilled and completed in 2019 (included in the table above), we were actively participating in the drilling of 22 gross (20 net) wells and had 66 gross (63 net) drilled but not completed wells as of January 31, 2020. These drilled but not completed wells represent wells that were being completed or were waiting on completion as of January 31, 2020.
Acreage
The following table sets forth the number of gross and net surface acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes that we held as of December 31, 2019. Undeveloped acreage includes leasehold interests containing proved undeveloped reserves.
|
| | | | | | | | | | | | | | | | | |
| | Developed Acres (1) | | Undeveloped Acres (2)(3) | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Midland Basin: | | | | | | | | | | | |
| RockStar | 67,113 |
| | 59,589 |
| | 4,966 |
| | 4,217 |
| | 72,079 |
| | 63,806 |
|
| Sweetie Peck | 17,007 |
| | 15,782 |
| | 2,835 |
| | 251 |
| | 19,842 |
| | 16,033 |
|
Midland Basin Total (4) | 84,120 |
| | 75,371 |
| | 7,801 |
| | 4,468 |
| | 91,921 |
| | 79,839 |
|
| Eagle Ford shale | 74,247 |
| | 71,296 |
| | 88,058 |
| | 87,631 |
| | 162,305 |
| | 158,927 |
|
Other (5) | 16,259 |
| | 11,363 |
| | 90,415 |
| | 25,599 |
| | 106,674 |
| | 36,962 |
|
| Total | 174,626 |
| | 158,030 |
| | 186,274 |
| | 117,698 |
| | 360,900 |
| | 275,728 |
|
| |
(1) | Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as developed acreage in the table above. |
| |
(2) | Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. |
| |
(3) | As of February 6, 2020, approximately 1,354, 184, and 155 net acres of undeveloped acreage are scheduled to expire by December 31, 2020, 2021, and 2022, respectively, if production is not established or we take no other action to extend the terms of the applicable leases. Certain of our Eagle Ford shale acreage is subject to lease consolidation agreements containing drilling, completion, and other obligations that we currently intend to satisfy. Failure to meet these obligations results in termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous development obligations required by individual leases are not met. |
| |
(4) | As of December 31, 2019, total Midland Basin acreage excludes approximately 1,940 net acres associated with drill-to-earn opportunities that we intend to pursue. |
| |
(5) | Includes other non-core acreage located in Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming. |
Delivery Commitments
As of December 31, 2019, we had gathering, processing, transportation throughput, and delivery commitments with various third-parties that require delivery of a minimum quantity of 24 MMBbl of oil and 424 Bcf of gas through 2023, and 18 MMBbl of produced water through 2027. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. We expect to fulfill our delivery commitments from a combination of production from our existing productive wells, future development of our proved undeveloped reserves, and future development of resources not yet characterized as proved reserves. Under certain of our commitments, if we are unable to deliver the minimum quantity from our production, we may deliver production acquired from third-parties to satisfy our minimum volume commitments.
As of December 31, 2019, in the event that no additional volumes are delivered in accordance with these agreements, the aggregate undiscounted future deficiency payments would total $218.5 million. This amount does not include deficiency payment estimates associated with approximately 16.5 MMBbl of future oil delivery commitments where we cannot predict with accuracy the amount and timing of these payments, as such payments are dependent upon the price of oil in effect at the time of settlement.
As of the filing of this report, we do not expect to incur any material shortfalls with regard to these commitments.
Major Customers
We do not believe the loss of any single purchaser of our production would materially impact our operating results, as oil, gas, and NGLs are products with well-established markets and other viable purchaser options are available in our operating regions.
The following major customers and entities under common control accounted for 10 percent or more of our total oil, gas, and NGL production revenue for at least one of the periods presented:
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
Major customer #1 (1) | 18 | % | | 18 | % | | 6 | % |
Major customer #2 (1) | 14 | % | | 5 | % | | 1 | % |
Major customer #3 (1) | 13 | % | | 7 | % | | — | % |
Major customer #4 (1) | 9 | % | | 10 | % | | 10 | % |
Group #1 of entities under common control (2) | 13 | % | | 18 | % | | 17 | % |
Group #2 of entities under common control (2) | 11 | % | | 12 | % | | 8 | % |
| |
(1) | These major customers are purchasers of a portion of our production from our Midland Basin assets. |
| |
(2) | In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of our total oil, gas, and NGL production revenue. |
Employees and Office Space
As of February 6, 2020, we had 530 full-time employees. This is a 13 percent decrease from the 611 full-time employees that we reported as of February 7, 2019. None of our employees are subject to a collective bargaining agreement.
The following table summarizes the approximate square footage of office space leased by us, as of December 31, 2019, including our corporate headquarters and regional offices:
|
| | | |
| | Approximate Square Footage Leased |
| Corporate | | 107,000 |
|
| Midland Basin | | 59,000 |
|
| South Texas | | 62,000 |
|
| Total | | 228,000 |
|
In addition to the leased office space summarized in the table above, as of December 31, 2019, we owned approximately 12,000 square feet of office space in South Texas.
Title to Properties
Substantially all of our oil and gas producing assets are held pursuant to oil and gas leases from third-party mineral owners. We obtain title opinions prior to commencing initial drilling operations on the properties we operate. We have obtained title opinions or have conducted other title review on substantially all of our producing properties and believe we have satisfactory title to such properties. Most of our producing properties are subject to mortgages securing indebtedness under our Credit Agreement, royalty and overriding royalty interests, liens for current taxes, and other ordinary course burdens that we believe do not materially interfere with the development of such properties. We typically perform title investigation in accordance with standards generally accepted in the oil and gas industry before acquiring developed and undeveloped leasehold acreage.
Seasonality
The price of crude oil is primarily driven by global socioeconomic factors and is less affected by seasonal fluctuations; however, demand for energy is generally higher in the winter and the summer driving season. The demand and price for gas frequently increases during winter months and decreases during summer months. To lessen the impact of seasonal gas demand and price fluctuations, pipelines, utilities, local distribution companies, and industrial users regularly utilize gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can divert gas that is traditionally placed into storage which, in turn, may increase the typical winter seasonal price. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.
Certain of our drilling, completion, and other operations are also subject to seasonal limitations. Seasonal weather conditions, government regulations, and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. Please refer to Risk Factors - Risks Related to Our Businessbelow for additional discussion.
Competition
The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and gas properties. We believe our acreage positions provide a foundation for development activities that we expect to fuel our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which in some cases have larger technical teams and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and gas reserves, but also have gathering, processing or refining operations, market refined products, provide, dispose of and transport fresh and produced water, own drilling rigs or production equipment, or generate electricity.
We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells, as well as for the gathering, transporting, and processing of oil, gas, NGLs and water. Consequently, we may face shortages, delays, or increased costs in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including renewable energy sources such as solar and wind-generated energy, and other fossil fuels such as coal. Competitive conditions may be affected by future energy, climate-related, financial, or other policies, legislation, and regulations.
In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to the evolving demographics of our industry. We are not insulated from competition for quality people, and we must compete effectively in order to be successful.
Government Regulations
Nearly every aspect of our business is subject to expansive federal, state, and local laws and governmental regulations. These laws and regulations frequently change in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential to increase our cost of doing business and consequently could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.
Energy Regulations
Texas, the state where we conduct operations and own nearly all of our oil and gas assets, has adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bond requirements in order to drill or operate wells, governing the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to Texas conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, Texas conservation laws establish maximum rates of production from oil and gas wells, generally limit or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce. FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for gas production.
Environmental, Health and Safety Matters
General. Our operations are subject to stringent and complex federal, state, and local laws and regulations governing protection of the environment and worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other things:
require the acquisition of various permits before drilling commences;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and
require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.
These laws, rules, and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes may result in more stringent, or different permitting, waste handling, disposal, and cleanup requirements for the oil and gas industry and could have a significant impact on our operating costs.
The following is a summary of some of the existing laws, rules, and regulations to which our business is subject.
Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Comprehensive Environmental Response, Compensation, and Liability Act. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release or threatened release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We currently own, lease, or operate numerous properties that have been used for oil and gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third-parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, pay fines, remediate contaminated property, or perform remedial operations to prevent future contamination.
Water discharges. The federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or analogous state agencies. The Clean Water Act also prohibits discharge of dredged or fill material into waters of the United States, including wetlands, except in accordance with the terms of a permit issued by the United States Army Corps of Engineers, or a state if the state has assumed authority to issue such permits. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.
Air emissions. The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing a comprehensive suite of regulations to restrict emissions of GHGs under existing provisions of the CAA. The Trump administration has taken steps to rescind or review many of these regulations. Legislative and regulatory initiatives related to climate
change could have an adverse effect on our operations and the demand for oil and gas. Please refer to Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs. In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products.
Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts on protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on these species. It is also possible that a federal or state agency could order a complete halt to activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.
National Environmental Policy Act. Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment to determine the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. The Trump administration has taken steps to modify NEPA’s implementing regulations intended to streamline the NEPA process. No new regulations have yet been finalized. Judicial and regulatory challenges are expected, and we cannot predict the outcome of any such challenges. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits subject to the requirements of NEPA. This process has the potential to delay development of some of our oil and gas projects.
OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe we are in substantial compliance with the applicable requirements of OSHA and comparable laws.
Hydraulic fracturing. Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water sources.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic fracturing techniques, which could potentially cause a decrease in the completion of new oil and gas wells, an increase in compliance costs, and delays, all of which could adversely affect our financial position, results of operations and cash flows. As new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local levels, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that we are ultimately able to produce from our reserves.
We believe it is reasonably likely that the trend in local and state environmental legislation and regulation will continue toward stricter standards, while the trend in federal environmental legislation and regulation faces an uncertain future under the Trump administration. While we believe we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the future.
Environmental, Health and Safety Initiatives. We are committed to exceptional safety, health, and environmental stewardship; making a positive difference in the communities where we live and work; and transparency in reporting on our progress in these areas. We set annual goals for our environmental, health and safety program focused on reducing the number of safety related incidents and the number and impact of spills of produced fluids. In addition, we set annual goals for GHG emissions intensity and methane emissions as a percentage of total methane produced. We also periodically conduct audits of our operations to ensure regulatory compliance and we strive to provide appropriate training for our employees. Reducing air emissions as a result of leaks, venting, or
flaring of gas during operations has become a major focus area for regulatory efforts and for our compliance efforts. While flaring is sometimes necessary, reducing these volumes is a priority for us. To avoid flaring when possible, we restrict testing periods and connect our production to gas pipeline infrastructure as quickly as possible after well completions. We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance. Such expenditures are included within our overall capital budget and are not separately itemized.
Available Information
Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC, and can be located at www.sec.gov. We also make available through our website our Corporate Governance Guidelines, Code of Business Conduct and Conflict of Interest Policy, Financial Code of Ethics, and the Charters of the Audit, Compensation, Executive, and Nominating and Corporate Governance Committees of our Board of Directors. Information on our website is not incorporated by reference into this report and should not be considered part of this document.
ITEM 1A. RISK FACTORS
In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us.
Risks Related to Our Business
Crude oil, naturalOil, gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.
Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and natural gas properties depend heavily on the prices we receive for crude oil, natural gas, and NGL sales. Crude oil, naturalOil, gas, and NGL prices also affect our cash flows available for capital expenditures and other items, our borrowing capacity, and the volume and amountvalue of our crude oil, natural gas, and NGL reserves. For example, the amount of our borrowing base under our Credit Agreement is subject to periodic redeterminationsredetermination based on crude oil, natural gas, and NGL prices specified by our bank group at the time of redetermination. In addition, we may have crude oil and natural gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. The decline in commodity prices during 2016 resulted in reductions to our proved reserve volumes and PV-10; reductions in revenues received from the sale of oil, gas, and NGLs, and thus cash flow from operating activities; and impairments of proved and unproved properties. Please refer to the captions Significant Developments in 20162019 and Reserves withinin Part I, Items 1 and 2 Comparison of Financial Results and Trends between 2016Between 2019 and 20152018 and between 2015Between 2018 and 2014 within2017 in Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies,Note 11 – Fair Value Measurements, andSupplemental Oil and Gas Information (unaudited) in Part II, Item 8 for specific discussion.
Historically, the markets for crude oil, natural gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in crude oil, natural gas, and NGL prices may result from relatively minor changes in the supply of and demand for crude oil, natural gas, and NGLs, market uncertainty, and other factors that are beyond our control, including:
global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole;
the level of consumer demand for crude oil, natural gas, and NGLs;
overall global and domestic economic conditions;
weather conditions;
the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized prices for crude oil, natural gas, or NGLs;areas;
liquefied natural gas deliveries to and from the United States;
the price and level of imports and exports of crude oil, refined petroleum products, and liquefied natural gas;
the price and availability of alternative fuels;
technological advances and regulations affecting energy consumption and conservation;
the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to agree to and maintain crudeeffective oil price and production controls;
political instability or armed conflict in crude oil or natural gas producing regions;
actual or perceived epidemic risks, such as the Coronavirus outbreak in early 2020;
strengthening and weakening of the United States dollar relative to other currencies;
stockholder activism or activities by non-governmental organizations to limit sources of funding or restrict the exploration and production of oil, gas, and NGLs and related infrastructure; and
governmental regulations and taxes.
These factors and the volatility of crude oil, natural gas, and NGL markets make it extremely difficult to predict future crude oil, natural gas, and NGL price movements with any certainty. Declines in crude oil, natural gas, and NGL prices would reduce our revenues and could also reduce the amount of crude oil, natural gas, and NGLs that we can produce economically, which could have a materially adverse effect on us.
Weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.
In recent years,the last decade, the United States and global economies and financial systems have experienced turmoil and upheaval characterized by extreme volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels of unemployment, and an unprecedented level of intervention by the United States federal government and other governments. AlthoughWeakness or uncertainty in the United States economy appears to have stabilized, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Renewed weakness in the United States or other large economies could materially adversely affect our business and financial condition. For example:
crude oil, natural gas, and NGL prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, leading to lower revenues, which could affect our financial condition and results of operations;
the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;
the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;
our ability or the ability of our suppliers or contractors to access the capital markets may be restricted or non-existent at a time when we or they would like, or need, to raise capital for our or their business, including for the exploration and/or development of reserves;
our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and
variable interest rate spread levels, including for LIBOR (or any applicable replacement rate) and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our Credit Agreement.
If we are unable to replace reserves, we will not be able to sustain production.
Our future operations depend on our ability to find, develop, orand acquire crude oil, natural gas, and NGL reserves that are economically producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate, and develop orand acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. Without successful drilling or acquisition activities, our reserves and production will decline over time. In addition, competitionCompetition for crude oil and natural gas properties is intense, and many of our competitors have financial, technical, human, and other resources necessary to evaluate and integrate acquisitions that are substantially greater than those available to us.
For our recentprior acquisitions, oras well as any future acquisitions we may complete, a successful impact onoutcome for our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price and transaction costs for the acquisition, future crude oil, natural gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation, and development activities on the acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. AOur customary review of subject propertiesin connection with acquisitions will not necessarily reveal, or allow us to fully assess, all existing or potential problems.
problems and deficiencies with such properties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. We often acquire interests in properties on an “as-is” basis with limited remedies for breaches of representations and warranties.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.
Integrating acquired businesses and properties involves a number of specialunique risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.
Substantial capital is required to develop and replace our reserves.
We must make substantial capital expenditures to find, acquire, develop, and produce crude oil, natural gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for crude oil, natural gas, and NGL sales, our success in locating, and developing and acquiring new reserves, and the orderly functioning of
credit and capital markets. If crude oil, natural gas, and NGL prices further decrease or if we encounter operating difficulties that result in our cash flows from operations beingare less than expected, we may further reduce our planned capital expenditures unless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may not always be of acceptable value to us. Any downgrades to our credit ratings may make it more difficult or expensive for us to borrow additional funds.
During 2016, our revenues decreased from 2015 due to continued declines in commodity prices and lower production; however, we were able to fund our capital program through cash flows from operations, proceeds from divestitures, and financing activities. If our revenues continue to decrease in the future due to lower crude oil, natural gas, or NGL prices, decreased production, or other reasons, and if we cannot obtain funding throughaccess sufficient liquidity under our Credit Agreement, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited.
Our ability to sell oil, gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines, and other transportation systems owned or operated by third-parties or by other interruptions beyond our control, which could obstruct, limit, or eliminate our access to oil, gas, and NGL markets.
The marketability of our oil, gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, pipelines, and other transportation systems, which are generally owned or operated by third-parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay, or discontinuance of development plans for our properties, or lower price realizations. Although we have some influence over the processing and transportation of our operated production, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil, gas, and NGL production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines or processing facilities, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, transport, or market oil, gas, and NGLs.
In particular, if production from the Midland Basin continues to grow, the amount of oil, gas, and NGLs being produced by us and others could exceed the capacity of, and result in constraints on, available gathering and transportation systems, pipelines, processing facilities, and other infrastructure. In such circumstances, it will be necessary for pipelines, gathering and transportation systems, processing facilities, and additional infrastructure to be expanded, built, or developed to accommodate anticipated production. Certain processing, pipeline, and other gathering, transportation, and infrastructure projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints, including regulatory constraints. Capital and other constraints could also limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices, which would adversely affect our results of operations and cash flows. In addition, the operations of the third-parties on whom we rely for gathering, processing, and transportation services are subject to complex and stringent laws and regulations, which require obtaining and maintaining numerous permits, approvals, and certifications from various federal, state, and local government authorities. These third-parties may incur substantial costs in order to comply with existing and future laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the availability and costs of such services. Similarly, a failure to comply with such laws and regulations by the third-parties on whom we rely could have a material adverse effect on our business, financial condition, and results of operations.
A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market or other conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flows and results of operations.
Downgrades in our credit ratings by various credit rating agencies could impact our access to capital and materially adversely affect our business and financial condition.
In February 2016, Moody’s Investors Service and Standard & Poor’s downgraded our credit ratings (“Debt Rating”). Our Debt Ratingdebt rating levels could have materially adverse consequences on our business and future prospects and could:
limit our ability to access debt markets, including for the purpose of refinancing our existing debt;
cause us to refinance or issue debt with less favorable terms and conditions, which debt may restrict, among other things, our ability to make any dividend distributions or repurchase shares;
negatively impact current and prospective customers’ willingness to transact business with us;
impose additional insurance, guarantee and collateral requirements;
limit our access to bank and third-party guarantees, surety bonds and letters of credit; and
cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding indebtedness.
We cannot provide assurance that any of our current Debt Ratings will remain in effect for any given period of time or that a Debt Rating will not be further lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant.
Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.
We face intense competition from major oil and gas companies, independent oil and gas exploration and production companies, and institutional and individual investors who seek oil and gas investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate crude oil and natural gas properties. Many of our competitors have financial, technical, and other resources exceeding those available to us, and many crude oil and natural gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. We may not be successful in acquiring and developing profitable properties in the face of this competition. In addition, other companies may have a greater ability to continue drilling activities during periods of low naturaloil or gas or oil prices and to absorb the burden of current and future governmental regulations and taxation. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. Also, we compete for human resources. Our inability to compete effectively with companies in any area of our business could have a material adverse impact on our business activities, financial condition, and results of operations.
The loss of key personnel could adversely affect our business.
We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of their services could adversely affect our business. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen, and other professionals. Competition for many of these professionals can be intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.
The actual quantities and present value of our proved crude oil, natural gas, and NGL reserves may be less than we have estimated.
This report and certain of our other SEC filings contain estimates of our proved crude oil, natural gas, and NGL reserves and the estimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to crude oil, natural gas, and NGL prices, drilling and completion costs, gathering and transportation costs, operating expenses, capital expenditures, effects of governmental regulation, taxes, timing of operations, and availability of funds. The process of estimating crude oil, natural gas, and NGL reserves is complex. The processcomplex and involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates depend on many variables, and changes often occur as our knowledge of these variables evolve.evolves. Therefore, these estimates are inherently imprecise. In addition, our reserve estimates for properties that do not have a significant production history may be less reliable than estimates for properties with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing and/or amount of development expenditures.
Actual future production; prices for crude oil, natural gas, and NGLs; revenues; production taxes; development expenditures; operating expenses; and quantities of producible crude oil, natural gas, and NGL reserves will most likely vary from those estimated. Any significant variance of any nature could materially affect the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities and present value may be significantly less than what we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of operations, results of exploration operations and development activity, prevailing crude oil, natural gas, and NGL prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties, which we may not control.
As of December 31, 2016,2019, 47 percent, or 187.1214.9 MMBOE, of our estimated proved reserves were proved undeveloped. In order to develop our proved undeveloped reserves, as of December 31, 2016,2019, we estimate approximately $1.5$2.0 billion of capital expenditures would be required. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated.
You should not assume that the PV-10 and standardized measure of discounted future net cash flows or PV-10 included in this report represent the current market value of our estimated proved crude oil, natural gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, the present value of our proved reserves as of December 31, 2016,2019, was estimated using calculated 12-month average sales prices of $42.75$55.69 per Bbl of oil (NYMEX WTI spot price), $2.47$2.58 per MMBtu of natural gas (NYMEX Henry Hub spot price), and $19.50$22.68 per Bbl of NGL (OPIS spot price). We then adjust these prices to reflect appropriate basis, quality and location differentials over the period in estimating our proved reserves. During 2016,2019, our monthly average realized crude oil prices before the
effect of derivative settlements were as high as $45.94$61.66 per Bbl and as low as $21.72$42.28 per Bbl for oil, were as high as $3.33 per Mcf and as low as $2.05 per Mcf for gas, and were as high as $21.81$20.06 per Bbl and as low as $11.07$13.84 per Bbl for NGLs. For the same period, our monthly average realized natural gas prices, excluding the effect of derivative settlements, were as high as $3.12 per Mcf and as low as $1.51 per Mcf. Many other factors will affect actual future net cash flows, including:
amount and timing of actual production;
supply and demand for crude oil, natural gas, and NGLs;
curtailments or increases in consumption by oil purchasers and natural gas pipelines;
changes in government regulations or taxes, including severance and excise taxes; and
escalations or reductions in service provider and equipment costs resulting from changes in supply and demand.
The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10. In addition, the 10 percent discount factor required by the SEC to be used to calculate PV-10 for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and natural gas industry in general are subject.
Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.
Successful property acquisitions require an assessment of a number of factors, some of which are beyond our control. These factors include exploration potential, future crude oil, natural gas, and NGL prices, operating costs, title to acquired properties, and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently uncertain.
In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface, title, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. We often acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties.
Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.
We regularly sell non-core assets in order to increase capital resources available for core assets and other purposes and to create organizational and operational efficiencies. We also occasionally sell interests in core assets for the purpose of accelerating the development and increasing efficiencies in other core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties andthird-parties, the availability of purchasers willing to acquire the assets oron terms we deem acceptable.acceptable, or other matters or uncertainties that could impact such dispositions, including whether transactions could be consummated or completed in the form or timing and for the value that we anticipate. We at times may be required to retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liabilities or of the indemnification obligations may be difficult to quantify at the time of the transaction and ultimately could be material.
We have limited control over the activities on properties we do not operate.
Some of our properties including a portion of our interests in the Eagle Ford shale in south Texas, are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator’s skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the expenditures of such properties. These limitations and our dependence on the operator and other working interest owners in these projects could cause us to incur unexpected future costs and materially and adversely affect our financial condition and results of operations.
We rely on third-party service providers to conduct drilling and completion and other related operations on properties we operate.
Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion and other related operations. The ability of third-party service providers to perform such operations will depend on those service providers’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, natural gas, and NGLs, prevailing economic conditions and financial, business, and other factors. In addition, continuedsustained low commodity prices maycould cause third-party service providers to consolidate or declare bankruptcy, which could limit our options for engaging such providers. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations.
Title to the properties in which we have an interest may be impaired by title defects.
We generally rely on title reports in acquiring oil and gas leasehold interests andinterests. We obtain title opinions onlyprior to commencing initial drilling operations on significantthe properties that we drill. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undevelopedoperate. Undeveloped acreage has greater risk of title defects than developed acreage. Titleacreage and title insurance is not generally available for oil and gas properties. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and title abstract facilities before acquiring a specific mineral interest and/or undertaking drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us.title. Generally, under the terms of the operating agreements affecting our properties, any monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such property. A material title defect can reduce the value of a property or render it worthless, thus adversely affecting our financial condition, results of operations, and operating cash flow if such property is of sufficient value.
Exploration and development drilling may not result in commercially producible reserves.
Crude oilOil and natural gas drilling, completion, and production activities are subject to numerous risks, including the risk that no commercially producible crude oil, natural gas, or associated liquidsNGLs will be found. The cost of drilling and completing wells is often uncertain, and crude oil, natural gas, or associated liquidsNGLs drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:may include, but are not limited to:
unexpected adverse drilling or completion conditions;
title problems;
disputes with owners or holders of surface interests on or near areas where we operate;
pressure or geologic irregularities in formations;
engineering and construction delays;
equipment failures or accidents;
hurricanes, tornadoes, flooding, or other adverse weather conditions;
governmental permitting delays;
compliance with environmental and other governmental requirements; and
shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.
The prevailing prices for crude oil, natural gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the available rigs in that region.
Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore or develop our properties.
The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if crude oil, natural gas, or NGLs are present, or whether they can be produced economically. The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling and completion costs. Even if sufficient amounts of crude oil, natural gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well, significant expenditure to repair the well, and/or the loss and abandonment of the well.
Results in our newer resource plays including those plays where we have recently acquired acreage, may be more uncertain than results in resource plays that are more developed and have longer established production histories. We and the industry generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in newer resource plays than other areas with longer histories of development and production. Drilling and completion techniques that have proven to be successful in other resource plays are being used in the early development of new plays; however, we can provide no assurance of the ultimate success of these drilling and completion techniques.
In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can be more susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so for locations booked as proved undeveloped locations, or if we will be able to produce crude oil, natural gas, or NGLs from these potential drilling locations.
Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate within a particular area may decline. In addition, weWe may not be able to obtain any options or lease rights in potential drilling locations that we identify. Unless production is established within the spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire and we will lose our right to develop the related properties. Our total net acreage expiring inas of February 6, 2020, that is scheduled to expire over the next three years, represents approximately 12one percent of our total net undeveloped acreage atas of December 31, 2016.2019. Although we have identified numerous potential drilling locations, we may not be able to economically drill for and produce crude oil, natural gas, or NGLs from all of them, and our actual drilling activities may materially differ from those presently identified, which could adversely affect our financial condition, results of operations and operating cash flow.
Part of our strategy involves drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
Many of our operations involve utilizing the latest drilling and completion techniques as developed by us, other operators and our service providers in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we face while drilling include, but are not limited to, landing our well bore outside the desired drilling zone, deviating from the desired drilling zone while drilling horizontally through the formation, the inability to run our casing the entire length of the well bore, and the inability to run tools and recover equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability to successfully clean out the well bore after completion of the final fracture stimulation.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and NGLs decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.
Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for crude oil, natural gas, and NGL sales.
To mitigate a portion of the exposure to potentially adverse market changes in crude oil, natural gas, and NGL prices and the associated impact on cash flows, we have entered into various derivative contracts. Our derivative contracts in place include swap arrangements for natural gas and NGLs, and both swap and collar arrangements for crude oil.oil, and swap arrangements for gas and NGLs. We have also entered into basis swap arrangements for a portion of our expected Midland Basin oil production to reduce volatility associated with location differentials between where these volumes are sold and NYMEX WTI. As of December 31, 2016,2019, we were in a net accrued liabilityasset position of $91.7$21.5 million with respect to our crude oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
our production is less than expected;
one or more counterparties to our commodity derivative contracts default on their contractual obligations; or
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.
The risk of one or more counterparties defaulting on their obligations is heightened by depressed crude oil, natural gas, and NGL prices. These circumstances may adversely affect the ability of our counterparties to meet their obligations to us pursuant to derivative transactions, which could reduce our revenues and cash flows from derivative settlements. As a result, our financial condition, results of operations, and cash flows could be materially affected in an adverse way if our counterparties default on their contractual obligations under our commodity derivative contracts.
In addition, commodity derivative contracts may limit the prices we receive for our crude oil, natural gas, and NGL sales if crude oil, natural gas, or NGL prices rise substantially over the price established by the commodity derivative contract.
The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from crude oil, natural gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other market conditions, including declines in crude oil, natural gas, and NGL prices. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices of commodities we sell. We do not believe the loss of any single purchaser would materially impact our operating results, as we have numerous options for purchasers in each of our operating regionsareas for our crude oil, natural gas, and NGL production. Please refer to Note 1 - Summary of Significant Accounting Policies, under the heading Concentration of Credit Risk and Major Customers in Note 1 – Summary of Significant Accounting Policies, in Part II, Item 8 of this report for further discussion of our concentration of credit risk and major customers. Additionally, the inability of our co-owners to pay joint interest billings could negatively impact our cash flowflows and financial ability to drill and complete current and future wells.
We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless of quantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of naturaloil, gas, crude oil, natural gas liquids,NGL, or produced water to our counterparties, our results of operations, financial position, and liquidity could be adversely affected.
As of December 31, 2016,2019, we were contractually committed to deliver 1,46124 MMBbl of oil and 424 Bcf of natural gas 70through 2023, and 18 MMBbl of crude oil, 13 MMBbl of natural gas liquids, and 25 MMBbl of water. These contracts expire at various datesproduced water through 2034.2027. We may enter into additional firm transportation agreements as we expand the development of our resource plays expands.plays. At the current time, we do not have enough proved developed reserves to offset these contractual liabilities, but we expect to develop reserves that will meet or exceed the commitments and therefore do not expect any material shortfalls. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, or if we further limit our capital expenditures due to furtherfuture commodity price declines or for other reasons, the requirements to pay for quantities not delivered could have a material impact on our results of operations, financial position, and liquidity.
Future crude oil, natural gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.
We follow the successful efforts method of accounting for our crude oil and natural gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If commercial quantities of hydrocarbons are not discovered with an exploratory well, the costs of drilling the well are expensed.
The capitalized costs of our oil and gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net cash flows, we generally must write down the costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. UnprovedWrite downs for unproved properties are also evaluated atfor carrying costs in excess of fair value. This evaluation considers the lower of cost or fair market value. Wepotential for abandonment due to lease expirations, losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. For the years ended December 31, 2019, 2018, and 2017, we incurred impairment of proved properties expenseoil and impairment of unprovedgas properties expense totaling $354.6$33.8 million, $49.9 million, and $80.4$16.1 million, respectively, during 2016, $468.7 million and $78.6 million, respectively, during 2015, and $84.5 million and $75.6 million, respectively, during 2014. We also incurred impairment of other property, plant, and equipment expense totaling $49.4 million during 2015. Commodity prices have declined in recent years starting in late 2014.respectively. If the prices of crude oil, natural gas, or NGLs continue to remain depressed or decline, further, or we have unsuccessful exploration efforts, it could cause additional proved and/or unproved property impairments in the future.
We review the carrying values of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and natural gas properties held for use cannot be reversed at a later date, even if crude oil, natural gas, or NGL prices increase.
Lower crude oil, natural gas, or NGL prices could limit our ability to borrow under our Credit Agreement.
Our Credit Agreement has a current commitment amount of $1.17$1.2 billion, subject to a borrowing base that the lenders redetermine semi-annually based on the bank group’s assessment of the value of our proved reserves, which in turn is impacted by crude oil, natural gas, and NGL prices. The borrowing base under our Credit Agreement is $1.17$1.6 billion, downup from $2.0$1.5 billion at December 31, 2015. This reduction was primarily a result of the sale of our Raven/Bear Den assets in the fourth quarter of 2016, non-core asset sales in the third quarter of 2016, as well as adjustments consistent with lower commodity prices. We expect a further reduction to our borrowing base during the2018. The next semi-annual redetermination date is scheduled for April 1, 2017, as a result of the anticipated sale of our outside-operated Eagle Ford shale assets, as well as the decrease in our proved reserves at December 31, 2016.2020. Divestitures of additional properties, incurrence of additional debt, or a further declinedeclines in commodity prices could limit our borrowing base and reduce the amount we can borrow under our Credit Agreement.
The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.
As of December 31, 2016,2019, we had $172.5the following outstanding long-term debt:
$476.8 million of long-term senior unsecured debt relating to our 6.125% Senior Notes due 2022 (“2022 Senior Notes”) that we issued on November 17, 2014;
$500.0 million of long-term senior unsecured debt relating to our 5.0% Senior Notes due 2024 (“2024 Senior Notes”) that we issued on May 20, 2013;
$500.0 million of long-term senior unsecured debt relating to our 5.625% Senior Notes due 2025 (“2025 Senior Notes”) that we issued on May 21, 2015;
$500.0 million of long-term senior unsecured debt relating to our 6.75% Senior Notes due 2026 (“2026 Senior Notes”) that we issued on September 12, 2016;
$500.0 million of long-term senior unsecured debt relating to our 6.625% Senior Notes due 2027 (“2027 Senior Notes”, and all senior notes collectively referred to as the “Senior Notes”) that we issued on August 20, 2018; and,
$172.5 million in aggregate principal amount of long-term senior unsecured convertible debt outstanding relating to our 1.50% Senior Convertible Notes due July 1, 2021 (“Senior Convertible Notes”) that we issued on August 12, 2016. As of December 31, 2016,
Additionally, we had $347.0$122.5 million of long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes due 2021 (“2021 Notes”) that we issued on November 8, 2011; $561.8 million of long-term senior unsecured debt outstanding relating to our 6.125% Senior Notes due 2022 (“2022 Notes”) that we issued on November 17, 2014; $395.0 million of long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes due 2023 (“2023 Notes”) that we issued on June 29, 2012; $500.0 million of long-term senior unsecured debt outstanding relating to our 5.0% Senior Notes due 2024 (“2024 Notes”) that we issued on May 20, 2013; $500.0 million of long-term senior unsecured debt outstanding relating to our 5.625% Senior Notes due 2025 (“2025 Notes”) that we issued on May 21, 2015; and $500.0 million of long-term senior unsecured debt outstanding relating to our 6.75% Senior Notes due 2026 (“2026 Notes”) that we issued on September 12, 2016 (collectively, the 2021 Notes, 2022 Notes, 2023 Notes, 2024 Notes, 2025 Notes, and 2026 Notes are referred to as our “Senior Notes”); and no outstanding borrowings under our secured credit facility. We had one outstanding letterCredit Agreement as of credit in the aggregate amount of $200,000 (which reduces the amount available for borrowing under the facility on a dollar-for-dollar basis),December 31, 2019, resulting in $1.2$1.1 billion of available borrowing capacity under our Credit Agreement, assuming the borrowing conditions will be met.secured credit facility. Our long-term debt represented 5450 percent of our total book capitalization as of December 31, 2016.2019.
Our indebtedness could have important consequences for our operations, including:
making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;
requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments;
limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;
placing us at a competitive disadvantage compared to our competitors with less debt; and
making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.
Our ability to make payments on our debt, refinance our debt, and fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors that are beyond our control. If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our Credit Agreement or from other sources, we might not be able to service our debt, issue additional debt, or fund our planned capital expenditures and other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, and/or restructure or refinance our debt. We might not be able to sell our equity, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our Credit Agreement and any future credit agreements, may prohibit us from pursuing any of these
alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, and availability of future financing.
Our debt agreements, including theour Credit Agreement and the indentures governing our Senior Convertible Notes and our Senior Convertible Notes, permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition, entities we may acquire in the future could have significant amounts of debt outstanding that we could be required to assume, and in some cases accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition.
As discussed above, our Credit Agreement is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals ofadjustments to our borrowing base or arrange new financing, we may be forced to sell significant assets.
The agreements governing our debt arrangements contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.
Our debt agreements, including our Credit Agreement and the indentures governing our Senior Notes and our Senior Convertible Notes, contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our Credit Agreement is subject to compliance with certain financial covenants. Financial covenants under the Credit Agreement require that our (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which will use annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending December 31, 2018, through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of each of the Company’sany fiscal quarters, our (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0.quarter. Our Credit Agreement also requires us to comply with certain additional financial covenants, including requirementsa requirement that we maintain certain levels of stockholders’ equity and limit our annual cash dividends to no more than $50.0 million. These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities. We were in compliance with all financial and non-financial covenants as of December 31, 2019, and through the filing of this report. Please refer to Non-GAAP Financial Measuresin Part II, Item 7 of this report for our definition of adjusted EBITDAX.
The respective indentures governing the Senior Notes and Senior Convertible Notes also contain covenants that, among other things, limit our ability and the ability of our subsidiaries to:
incur additional debt;
make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capitalcommon stock;
sell assets, including capitalcommon stock of our subsidiaries;
restrict dividends or other payments of our subsidiaries;
create liens that secure debt;
enter into transactions with affiliates; and
merge or consolidate with, or transfer or lease all or substantially all of our assets to another company.
Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.
Our increasing dependence on digital technologies puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruptions or financial loss.
We are subject to cybersecurity risks. The oil and gas industry is increasingly dependent on digital technology in all aspects of our business. We use digital technology to conduct certain of our drilling development, production and gathering activities, manage drilling rigs and completion equipment, gather and interpret seismic data, conduct reservoir modeling, record financial and operating data, and maintain employee and other databases. Our service providers, including those who gather, process and market our oil, gas and NGLs, are also increasingly reliant on digital technology. Our and their reliance on this technology increasingly puts us at risk for technology system failures, data or network disruptions, cyberattacks and other breaches in cybersecurity. Power failures, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire, flood, human error or other means could significantly impair our ability to conduct our business.
Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. Deliberate attacks on, or security breaches in our systems, infrastructure, the systems and infrastructure of third-parties, or cloud-based applications could lead to disclosure of confidential information, a corruption or loss of our proprietary data, delays in production or exploration activities, difficulty in completing or settling transactions, challenges in maintaining our books and records, environmental damage, communication or other operational disruptions, and liability to third parties. Any insurance we might obtain in the future may not provide adequate protection from these risks. Any such events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. As these cyber risks continue to evolve and our dependence on digital technologies grows, we may be required to expend significant additional resources to continue to modify or enhance our protective measures and remediate cyber vulnerabilities.
Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.
As an oil, gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
The threat of terrorism and the impact of military and other actions have caused instability in world financial markets and could lead to increased volatility in prices for oil, gas, and NGLs, all of which could adversely affect the markets for our production. Energy assets might be specific targets of terrorist attacks. While we currently maintain some insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms we consider reasonable, or at all. In addition, this insurance may not cover all of our losses for a terrorist attack. These developments have subjected our operations to increased risk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business, financial condition, or results of operations.
Negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole could adversely affect our business, operations and our ability to attract capital.
Certain segments of the public as a whole, and the investment community in particular, have developed negative sentiment towards our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment management firms, sovereign wealth and pension funds, university endowments and other investment advisors, have adopted policies to discontinue or reduce their investments in the oil and gas sector based on social and environmental considerations. Furthermore, other influential stakeholders have pressured commercial and investment banks to reduce or cease financing of oil and gas companies and related infrastructure projects.
Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured.
Oil and gas operations are subject to many risks, including human error and accidents, that could cause personal injury, death, property damage, well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas and associated liquids,NGLs, or well fluids, releases or spills of completion fluids, spills or releases from facilities and equipment used to deliver or store these materials, spills or releases of brine or other produced or flowback water, subsurface conditions that prevent us from stimulating the planned number of completion stages, accessing the entirety of the wellbore with our tools during completion, or removing materials from the wellbore to allow production to begin, fires, adverse weather such as hurricanes or tornadoes, freezing conditions, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, seismic events, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses.
Furthermore, if we experience any of the problems with well stimulation and completion activities referenced above, our ability to explore for and produce crude oil, natural gas, or NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of the need to shutdown,shut down, abandon, or relocate drilling operations, the need to modify drill sites to lessen the risk of spills or releases, the need to investigate and/or remediate any spills, releases or ground water contamination that might have occurred, and the need to suspend our operations.
There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling, and disposal of materials, including produced water, solid and hazardous wastes, and petroleum hydrocarbons. We may incur joint and several, and/or strict liability under applicable United States federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from our leased or owned properties, some of which have been used for naturaloil and gas and oil exploration and production activities for a number of years, often by third partiesthird-parties not under our control. For our outside-operated properties, we are dependent on the operator for operational and regulatory compliance and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or therefrom could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the CERCLA or the Superfund law, the RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under anyvarious implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third partiesthird-parties to file claims for personal injury or property damage, including induced seismicity damage, allegedly caused by the release of petroleum hydrocarbons or other hazardous substances into the environment. As a result, we may incur substantial liabilities to third partiesthird-parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses.
We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by environmental damage that occurs gradually over time is appropriate for us at this time given the nature of our operations and the nature and cost of such coverage. Further, we may elect not to obtain insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss.
Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks.
Federal, state, tribal, and local authorities extensively regulate the oil and natural gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing, or marketing of crude oil, natural gas, and NGL production. NoncomplianceNon-compliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.
Governmental authorities regulate various aspects of drilling for and the production of crude oil, natural gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oil and natural gas properties, rights-of-way and easements, disposal of produced water, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, and restoration standards, and oil and gas operations. Public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Federal authorities also may require any of our ongoing or planned operations on federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our operations.
Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, including the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate in, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, and triballocal environmental laws for noise emissions and for discharges of crude oil, natural gas, and associated liquidsNGLs or other pollutants into the air, soil, surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and remediation for these emissions and discharges and other compliance issues. Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs, but also natural resources, real or personal property and other damages and civil and criminal liabilities. The listing of additional wildlife or plant species as federally endangered or threatened could result in limitations on exploration and production activities in certain locations. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us.
SeasonalThe impact of extreme weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Operations in certain ofOur operations on our regions, such as our Rocky MountainMidland Basin and Permian regions,South Texas assets are adversely affected by seasonalthe impact of extreme weather conditions and lease stipulations designed to protect various wildlife or plant species. In certain areas, on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs and completion equipment, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. Possible restrictions may include seasonal restrictions in greater sage-grouse habitat during breeding and nesting seasons, within a certain distance of active raptor nests during fledging, and in big game winter or parturition ranges during winter or calving seasons. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing, air quality, and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is a common practice in the oil and gas industry used to stimulate the production of oil, natural gas, and NGLs from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Wolfcamp and Spraberry shale intervals in thewithin our Midland Basin the Eagle Ford shale of southand South Texas and the Bakken/Three Forks formations in North Dakota.assets. Hydraulic fracturing involves injecting water, sand, and certain chemicals under pressure to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas commissions. However, the EPA and other federal agencies have asserted federal regulatory authority over certain aspects of hydraulic fracturing activities, as outlined below.
The EPA has authority to regulate underground injections that contain diesel in the fluid system under the SDWA.Safe Drinking Water Act. The EPA has published an interpretive memorandum and permitting guidance related to regulation of fracturing fluids using this regulatory authority. In June 2016, the EPA issued regulations under the Federal Clean Water Act establishing federal pre-treatment standards for wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process in the Federal Register. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it to publicly-owned
treatment facilities.process. Under a recent settlement, the EPA will decide byhad until March 2019 to decide whether to initiate rulemaking governing the disposal of wastewater from oil and gas development.development under RCRA Subtitle D. In April 2019, the EPA released its review, concluding that no new regulations were needed for managing wastewater based on the EPA’s conclusion that existing state regulations and best management practices are sufficiently protective of human health and the environment. If the EPA implements further regulations of hydraulic fracturing, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.
Certain states, in which we operate, including Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict, or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. Recently, several municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city boundaries, setting the stage for challenges by state regulators and third-parties. Similar events and processes are playing out in several cities, counties, and townships across the United States. In the event that state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.
SeveralIn the recent past, several federal governmental agencies arewere actively involved in studies or reviews that focus on environmental aspects and impacts of hydraulic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. InFor example, in December 2016, the EPA issued a final assessment of potential impacts to drinking water resources from hydraulic fracturing. The EPA’s inspector general released a report on July 16, 2015 recommending increased EPA oversightOn March 28, 2017, President Trump issued Executive Order 13783 entitled “Promoting Energy Independence and Economic Growth” (“Executive Order 13783”). Executive Order 13783 directed executive departments and agencies to review regulations that potentially burden the development or use of permit issuances as well as the chemicals used in hydraulic fracturing. The United States Department of Energy is also actively involved in research on hydraulic fracturing practices, including groundwater protection.
On March 26, 2015,domestically produced energy resources and, as appropriate, suspend, revise, or rescind those that unduly burden domestic energy resources development.
We will continue to be subject to uncertainty associated with new regulatory suspensions, revisions or rescissions and inconsistent state and federal regulatory mandates that could adversely affect our production.
Further, as to air quality and GHG regulation of oil and gas sources, the Bureauoverall trend has been toward increased regulation and requirements for reduced emissions. The Trump administration has taken steps toward rescinding or reviewing many of Land Management (“BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands, including private surface lands with underlying federal minerals.those regulations, but any deregulation will likely face immediate judicial challenges. The rule was scheduled to become effective on June 24, 2015, but was temporarily stayed by a federal court. The rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in hydraulic fracturing operations meet certain construction standards, development of appropriate plans for managing flowback water that returns to the surface, heightened standards for interim storage of recovered waste fluids, and submission of detailed information to the BLM regarding the geology, depth and location of pre-existing wells. AlthoughObama administration took several states, tribes, and industry groups filed several pending lawsuits challenging the rule and the BLM’s authorityactions to regulate hydraulic fracturing, the outcomeair quality and GHGs, many of this litigation is uncertain. If the rule becomes effective, we expect to incur additional costs to comply with such requirements that may be significantwhich remain in nature, and we could experience delays or even curtailment in the pursuit of hydraulic fracturing activities in certain wells on federal and Indian lands. The rule could also affect drilling units that include both private and federal mineral resources.
Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. If hydraulic fracturing becomes regulated at the federal level, our fracturing activities could become subject to additional permit or disclosure requirements, associated permitting delays, operational restrictions, litigation risk, and potential cost increases. Additionally, certain members of Congress have called upon the United States Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the United States Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The United States Geological Survey Offices of Energy Resources Program, Water Resources and Natural Hazards and Environmental Health Offices also have ongoing research projects on hydraulic fracturing. These ongoing studies, depending on their course and outcomes, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory processes.
Further,effect. For example, on August 16, 2012, the EPA issued final rules subjecting all new and modified oil and gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (“NSPS”) and all existing and new operations to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards require the use of reduced emission completion (“REC”) techniques developed in the EPA’s Natural Gas STAR program along
with the pit flaring of gas not sent to the gathering line beginning in January 2015. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAP include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and certain storage vessels at major sources of hazardous air pollutants not currentlypreviously subject to MACT standards. These rules will require additional control equipment, changes to procedure, and extensive monitoring and reporting. The EPA stated in JanuaryIn September 2013 however, that it intends to reconsider portions of the final rule. On September 23, 2013,and December 2014, the EPA published newtechnical fixes to the 2012 NSPS, including standards for storage tanks subject to the NSPS. In December 2014, the EPA finalized additional updates to the 2012 NSPS. The amendments clarified stages for flowback and the point at which green completion equipment is required and updated requirements for storage tanks and leak detection requirements for processing plants. In October 2016, the EPA denied the remaining petitions for reconsideration with respect to the issues not otherwise addressed in the previous reconsideration actions. As part of the EPA’s strategy during the Obama administration to reduce methane and ozone-forming VOCvolatile organic compound (“VOC”) emissions from the oil and gas industry, on May 12, 2016, the EPA issued final regulations that amend and expand the 2012 regulations by setting emission limits for greenhouse gases, or GHGs, and added requirements for previously unregulated sources.regulations. The 2016 NSPS requires reduction of greenhouse gasesGHGs in the form of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September 18, 2015. The final regulation requires, among other things, GHG and VOC emission limitsstandards for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and natural gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well completions. Both the 2012 and 2016 rules are the subjects of Petitions for Review before the U.S. Circuit Court of Appeals for the District of Columbia.Columbia, though the litigation of both rules has been stayed. In June 2017, the EPA proposed a 2-year stay of the compliance requirements in the 2016 NSPS. In a related action in November of 2016,March 2017, the EPA issued oil and gas companies awithdrew the final information request it had issued in 2016 as part of an effort to develop standards under the Clean Air ActCAA NSPS provisions for methane and other emissions from existing sources in the oil and natural gas industry. The request requires companies to provideIn September 2018, the EPA with a wide range of informationproposed changes to the 2016 NSPS amending specific provisions related to, operations, equipment,among other things, fugitive emissions requirements. On August 29, 2019, the EPA proposed amendments to the 2012 and 2016 NSPS that would remove transmission and storage infrastructure from regulation of methane emissions controls within 180 daysand other VOCs. The amendments would also rescind methane requirements for oil and gas production and processing equipment. As an alternative, the EPA proposed to rescind the methane requirements for oil and gas altogether and sought comment on alternative interpretations of receipt. It is unclear whetherits authority to regulate pollutants under Section 111 of the Trump Administration will proceed with developing an existing source rule based on the information collected through this request.
Clean Air Act.
In October 2015, the EPA revised and lowered the ambient air quality standard for ozone in the U.S. under the Clean Air Act,CAA, from 75 parts per billion to 70 parts per billion, which is likely to result in more, and expanded, ozone non-attainment areas, which in turn will require states to adopt implementation plans to reduce emissions of ozone-forming pollutants, like VOCs and nitrogen oxides, that are emitted from, among others, the oil and gas industry. Opponents to the new ozone standards challenged the agency’s action in federal court. In August 2019, the D.C. Court of Appeals upheld the health-based ozone standards, but remanded to the EPA the secondary, public welfare standards designed to protect environmental values. The 2015 ozone standard is being implemented pursuant to the EPA’s December 2018 final implementation rule. In October 2016, the EPA finalized Control Techniques Guidelines for VOC emissions from existing oil and natural gas equipment and processes in moderate ozone non-attainment areas. These Control Techniques Guidelines provide recommendations for states and local air agencies to consider when determining what emissions requirements apply to sources in the non-attainment areas. The EPA has proposed to completely withdraw the rules. On May 12, 2016, the EPA also issued a final rule named the “Source Determination Rule” that was issued to clarify when multiple pieces of oil and gas equipment and activities must be aggregated as a single source for determining whether major source permitting programs apply. This action can expand the permitting and related control requirements to sources that were not previously subject to permitting requirements.
However, more recently, the EPA has issued several guidance documents and memorandums related to aggregation of facilities that may narrow the effect of the Source Determination Rule.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third partiesthird-parties opposing such activities to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. Over the past year, several court cases have addressed aspects of hydraulic fracturing. In a case that could delay operations on public lands,2013, a court in California held that the BLMBureau of Land Management (“BLM”) did not comply with NEPA because it did not adequately consider the impact of hydraulic fracturing and horizontal drilling before issuing leases. Courts in New York and Colorado reduced the level of evidence required before a court will agree to consider alleged damage claims from hydraulic fracturing by property owners. Litigation resulting in financial compensation for damages linked to hydraulic fracturing,
including damages from induced seismicity, could spur future litigation and bring increased attention to the practice of hydraulic fracturing. Judicial decisions could also lead to increased regulation, permitting requirements, enforcement actions, and penalties. Additional legislation or regulation could also lead to operational delays or restrictions or increased costs in the exploration for, and production of, oil, natural gas, and associated liquids,NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws, or the implementation of new regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows.
Requirements to reduce gas flaring could have an adverse effect on our operations.
Wells in the Bakken and Three Forks formationsMidland Basin in North Dakota,Texas, where we have significant operations, produce natural gas, as well as crude oil.oil and NGLs. Constraints in the current gas gathering and processing network in certain areas of the Midland Basin have resulted in somesignificant quantities of that natural gas being flared instead of gathered, processed, and sold. In June 2014,Further, we are subject to laws established by state and other regulatory agencies that restrict the North Dakota Industrial Commission, North Dakota’s chief energy regulator, adopted a policy to reduce the volumeduration and amount of natural gas flared from oil wells inthat can be legally flared. These laws and regulations, including potential future regulations that may impose further restrictions on flaring, could limit the Bakken and Three Forks formations. The Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. In November 2016, the BLM finalized regulations to address methane emissions fromamount of oil and gas operations on federal and tribal lands. The regulations prohibit venting gas except in limited situations andwe can produce from our wells or may limit the flaringnumber of gas. These capture requirements,wells or the locations that we can drill. Any future laws and any similar future obligations in North Dakota or our other locations,regulations may increase our operational costs, or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.
Our ability to produce crude oil, natural gas, and associated liquidsNGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.
The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercial quantities of crude oil, natural gas, and NGLs requires the use and disposal of significant quantities of water.
Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used inproduced from our operations,wells, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of crude oil, natural gas, and NGLs.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.
Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production could be eliminated or modified as a result of future legislation.
Budget proposals in recent years, if enacted into law, would have eliminated certain key United States federal income tax incentives available to oil and natural gas exploration and production companies. The proposals included:
the elimination of current deductions for intangible drilling and development costs;
the repeal of the percentage depletion allowance for oil and natural gas properties;
the elimination of the deduction for certain domestic production activities; and
an extension of the amortization period for certain geological and geophysical expenditures.
Congress is currently considering tax reform proposals which could have a significant impact on business taxes and it could be that none of these or similar changes will be enacted. The passage of legislation eliminating or postponing certain tax deductions currently available with respect to oil and natural gas exploration and development could have an adverse effect on our financial position, results of operations and cash flows.
Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural gas, and NGLs.
In December 2009, the EPA made a finding that emissions of carbon dioxide, methane, and other “greenhouse gases”GHGs endanger public health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on this finding, the EPA adopted and implemented a comprehensive suite of regulations to restrict and otherwise regulate emissions of greenhouse gasesGHGs under existing provisions of the CAA. In particular, the EPA has adopted two sets of rules regulating greenhouse gasGHG emissions under the CAA. One rule requires a reduction in greenhouse gasGHG emissions from motor vehicles, and the other regulates permitting and greenhouse gasGHG emissions from certain large stationary sources. These EPA regulatory actions have been challenged by various industry groups, initially in the D.C. Circuit, which in 2012 ruled in favor of the EPA in all respects. However, in June 2014, the United States Supreme Court reversed the D.C. Circuit and struck down the EPA’s greenhouse gasGHG permitting rules to the extent they impose a requirement to obtain a permit based solely on emissions of greenhouse gases.GHGs. The EPA proposed a rule in 2016 to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits addressing emissions of greenhouse gasesGHGs to large sources of other air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). If finalized, large sources of air pollutants other than greenhouse gasesGHGs will be required to implement the best available capture technology for greenhouse gases.GHGs. However, the EPA has not taken action on the proposed rule and is unlikely to do so under the Trump administration. The EPA has also adopted reporting rules for greenhouse gasGHG emissions from specified greenhouse gasGHG emission sources in the United States, including petroleum refineries as well as certain onshore oil and natural gas extraction and production facilities.
Several other kinds of cases on greenhouse gasesregarding GHGs have been heard by the courts in recent years. While courts have generally declined to assign direct liability for climate change to large sources of greenhouse gasGHG emissions, some have required increased scrutiny of such emissions by federal agencies and permitting authorities. There is a continuing risk of claims being filed against companies that have significant greenhouse gasGHG emissions, and new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue. Such cases often seek to challenge air emissions permits that greenhouse gasGHG emitters apply for, seek to force emitters to reduce their emissions, or seek damages for alleged climate change impacts to the environment, people, and property. Any court rulings, laws, or regulations that restrict or require reduced emissions of greenhouse gasesGHGs could lead to increased operating and compliance costs and could have an adverse effect on demand for the oil and natural gas that we produce.
The United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases,GHGs, and almost one-half of the states have already taken measures to reduce emissions of greenhouse gases,GHGs, primarily through the planned development of greenhouse gasGHG emission inventories and/or regional greenhouse gasGHG “cap and trade” programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gasGHG emission reduction goal. Recently,In 2013, the Congressional Budget Office provided Congress with a study on the potential effects on the United States economy of a tax on greenhouse gas emissions.GHG emissions and recently summarized the impact of imposition of a tax on GHG emissions for reducing the deficit. While “carbon tax” legislation has been introduced in the Senate,Congress, the prospects for passage of such legislation are highly uncertain at this time.
On June 25, 2013, President Obama outlined plansissued a Climate Action Plan to address climate change through a variety of executive actions, including reduction of methane emissions from oil and gas production and processing operations as well as pipelines and coal mines (the “Climate Action Plan”). The President’s Climate Plan, along with recent regulatory initiatives and ongoing litigation filed by states and environmental groups, signal a new focus on methane emissions, which could pose substantial regulatory riskPlease refer to our operations. In March 2014, President Obama released a strategy to reduce methane emissions, which directed the EPA to consider additional regulations to reduce methane emissions from the oil and gas sector. On January 14, 2015, the Obama Administration announced additional steps to reduce methane emissions from the oil and gas sector by 40 to 45 percent by 2025. These actions include a commitment from the EPA to issue new source performance standards for methane emissions from the oil and gas sector. Pursuant to this commitment, in October 2016, the EPA finalized emission standards for methane and VOC for sources in the oil and gas sector constructed or modified after September 1, 2015. See Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing, air quality, and greenhouse gas emissions could result in increased costs and additional operating restrictions or delaysfor more information on this rule and steps the EPA has takenactions to address existing sources. On November 16, 2016, the BLM finalized regulations to address methane emissions from oil and gas operations on federal and tribal lands, as part ofimplement the Climate Action Plan. The regulations, named the Methane and Waste Prevention Rule, are intended to reduce the waste of natural gas from flaring, venting, and leaks by oil and gas production. The rule includes requirements that prohibit venting gas except in limited circumstances and limit flaring of gas and includes requirements for leak detection and
repair. The rule also increases royalty payments for “waste” gas that is released in contravention of the rule requirements. The rule, which was immediately challenged in federal district court, faces an uncertain future in the Trump Administration and is a potential target of rescission through the Congressional Review Act. The focus on legislating and/or regulating methane also could eventually result in:
•requirements for methane emission reductions from existing oil and gas equipment;
•increased scrutiny for sources emitting high levels of methane, including during permitting processes;
•analysis, regulation and reduction of methane emissions as a requirement for project approval; and
•actions taken by one agency for a specific industry establishing precedents for other agencies and
industry sectors.
In relation to the Climate Action Plan, both assumed Global Warming Potentialglobal warming potential (“GWP”) and assumed social costs associated with methane and other greenhouse gasGHG emissions have been finalized, including a 20% increase in the GWP of methane. Changes to these measurement tools could adversely impact permitting requirements, application of agencies’ existing regulations for source categories with high methane emissions, and determinations of whether a source qualifies for regulation under the CAA. TheHowever, in Executive Order 13783, President Trump ordered a review of the use of social cost of carbon for regulatory impact analysis. Therefore, the continued use of the social cost of carbon under the Trump Administrationadministration is uncertain.
Finally, it should be noted that some scientists have predicted that increasing concentrations of greenhouse gasesGHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. Some scientists refute these predictions. However, President Obama’s Climate Plan emphasizes preparation for such events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such events. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies, or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change. Federal regulations or policy changes regarding climate change preparation requirements could also impact our costs and planning requirements.
Our ability to sell crude oil, natural gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines and other transportation systems owned or operated by others or by other interruptions.
The marketability of our crude oil, natural gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, pipelines, and other transportation systems owned or operated by third parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price realizations. Although we have some contractual control over the processing and transportation of our operated production, material changes in these business relationships could materially affect our operations. Federal and state regulation of crude oil, natural gas, and NGL production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, and transport crude oil, natural gas, and NGLs.
In particular, if drilling in the Midland Basin continues to be successful, the amount of crude oil, natural gas, and NGLs being produced by us and others could exceed the capacity of, and result in strains on, the various gathering and transportation systems, pipelines, processing facilities, and other infrastructure available in that area. It will be necessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to be expanded, built or developed to accommodate anticipated production from these areas. Because of the current commodity price environment, certain processing, pipeline, and other gathering or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints, including permitting constraints. Capital and other constraints could also limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity
expansion and/or sell production at significantly lower prices, which would adversely affect our results of operations and cash flows. In addition, the operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations, which require obtaining and maintaining numerous permits, approvals, and certifications from various federal, state, tribal and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the amounts we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations.
A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily and adversely affect our cash flows and results of operations.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services that use new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies we currently use or implement in the future may become obsolete. We cannot be certain we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations, and financial condition may be adversely affected.
Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.
As a crude oil, natural gas, and NGLs producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for crude oil, natural gas, and NGLs, all of which could adversely affect the markets for our operations. Energy assets might be specific targets of terrorist attacks. These developments have subjected our operations to increased risk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business.
Risks Related to Our Common Stock
The price of our common stock may fluctuate significantly, which may result in losses for investors.
From January 1, 2016,2019, to February 15, 2017,6, 2020, the low and high intraday trading prices per share of our common stock as reported by the New York Stock Exchange ranged from a low of $6.99$6.85 per share in February 2016October 2019 to a high of $43.09$21.19 per share in October 2016.January 2019. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:include, in addition to the other risk factors set forth herein, the following:
changes in crude oil, natural gas, or NGL prices;
changes in the outlook for regional, national, or global commodity supply and demand;
variations in drilling, recompletion, and operating activity;
changes in financial estimates by securities analysts;
changes in market valuations of comparable companies;
additions or departures of key personnel;
increased volatility due to the impacts of algorithmic trading practices;
future sales of our common stock; and
changes in the national and global economic outlook.outlook, including potential impacts from trade agreements; and
international trade relationships, potentially including the effects of trade restrictions or tariffs affecting the raw materials we utilize and the commodities we produce in our business.
We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result.
Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment, which could adversely affect the price of our common stock.
Delaware corporate law and our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control of us or our management. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price investors are willing to pay in the future for shares of our common stock.
Shares eligible for future sale may causeIn addition, stockholder activism in our industry has been increasing, and if investors seek to exert influence or affect changes to our business that we do not believe are in the market pricelong-term best interests of our common stock to drop significantly, even ifstockholders, such actions could adversely impact our business is doing well.
The potential for salesby, among other things, distracting our Board of substantial amountsDirectors and management team, causing us to incur unexpected advisory fees and other related costs, impacting execution of our common stock in the publicstrategic objectives, and creating unnecessary market may have a materially adverse effect on our stock price. As of February 15, 2017, 97,871,754 shares of our common stock were freely tradable without substantial restriction or the requirement of future registration under the Securities Act. In addition, (a) approximately 13.4 million shares issued pursuant to the QStar Acquisition were subject to a Lock-Up and Registration Rights Agreement that prohibits sale of such stock until no earlier than the 90th day after issuance; (b) restricted stock units (“RSUs”) providing for the issuance of up to a total of 591,380 shares of our common stock were outstanding; and (c) 865,598 performance share units (“PSUs”) were outstanding. The PSUs represent the right to receive, upon settlement of the PSUs after the completion of a three-year performance period, a number of shares of our common stock that may be from zero to two times the number of PSUs granted, depending on the extent to which the underlying performance criteria have been achieved and the extent to which the PSUs have vested. As of February 15, 2017, there were 111,257,703 shares of our common stock outstanding.
uncertainty.
We may not always pay dividends on our common stock.
Payment of future dividends remains at the discretion of our Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our Credit Agreement limiting our annual cash dividends to no more than $50.0 million, and to covenants in the indentures for our Senior Notes and Senior Convertible Notes that limit our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share or discontinue the payment of dividends altogether.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Exchange Act.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectively couldare likely to have a materially adverse effect upon our financial condition, results of operations or cash flows.
Chieftain Royalty Company v. SM Energy Company, Case No. CIV-11-D, In the United States District Court, Western District of Oklahoma. On January 27, 2011, Chieftain Royalty Company (“Plaintiff”) commenced a putative class action lawsuit against the Company by filing a Petition in the District Court of Beaver County, Oklahoma, in the matter originally styled Chieftain Royalty Company v. SM Energy Company (including predecessors, successors and affiliates), Case No. CJ-201104, alleging that the Company had improperly deducted post-production costs from royalty payments due on production from wells located throughout Oklahoma, and asserting claims against the Company for breach of contract, tortious breach of contract, breach of fiduciary or quasi-fiduciary duty, fraud (actual and constructive), deceit, conversion and conspiracy. The Company removed the case to the United States District Court for the Western District of Oklahoma.
On August 2, 2018, the Court required that Plaintiff file any motion to certify a class by February 8, 2019. Plaintiff filed such motion but limited to royalty owners in wells related to the Coal County, Oklahoma pipeline system, which was owned by the Company’s affiliate, Four Winds Marketing, LLC, until 2015, when the subject wells and pipeline system were sold to a third party. The Company opposed the Motion and it remains at issue and pending.
This case involves complex legal and factual issues and uncertainties as to Oklahoma law and federal law concerning class certification under the circumstances of this case, and has resulted in a significant amount of discovery. The Company believes that it has properly paid royalties under Oklahoma law and that the class as proposed by Plaintiff should not be certified. The Company has and will continue to vigorously defend this case.
SPM NAM LLC. et al., v. SM Energy Company, Case No. 2018-07160, in the 189th Judicial District of Harris County, Texas (the “Lawsuit”). Plaintiff SPM NAM LLC (“SPM”) filed the Lawsuit against the Company on February 1, 2018. The Lawsuit concerns the Acquisition and Development Funding Agreement dated August 2, 2016 (together with its amendments, the “ADFA”). The parties to the ADFA (and its amendments) are the Company; SPM; and certain affiliates of SPM-(1) Schlumberger Technology Corporation; (2) Smith International, Inc.; (3) M-I, L.L.C.; and (4) Cameron International Corporation (the “Schlumberger Service Providers”). In the Lawsuit, SPM and the Schlumberger Service Providers are the plaintiffs, and the Company is the defendant.
In the Lawsuit, SPM alleges that the Company breached the ADFA in connection with the Company’s agreement to sell its interests in the Powder River Basin (collectively, the “Company Interests”) to a third party (“Buyer”). SPM alleges that pursuant to the ADFA, SPM was entitled to sell its related wellbore interests to Buyer on the same terms and conditions that the Company Interests were to be sold, through a “tag-along” process. SPM alleges that the Company failed to honor the tag-along provisions of the ADFA. The Lawsuit further alleges that the Company fraudulently induced SPM to enter an amendment to the ADFA in connection with its sale. SPM brings claims for rescission, fraud, breach of contract, unjust enrichment, breach of good faith and fair dealing, and declaratory judgment. SPM has not specified the damages it seeks in its pleadings, except to state that they are more than $1,000,000.
The Company has asserted affirmative defenses and counterclaims, that in part allege that: (1) SPM has breached the ADFA by filing an action for rescission, when any rescission remedy is expressly barred by the ADFA; and (2) the Company is entitled to a declaration that the Company has complied with the ADFA; and (3) SPM’s tag-along rights under the ADFA expired.
The case is in discovery, and trial is scheduled for June 22, 2020. The Company believes it has complied with the terms of the ADFA, intends to vigorously defend against SPM’s claims, and intends to vigorously prosecute its own claims.
ITEM 4. MINE SAFETY DISCLOSURES
These disclosures are not applicable to us.
PART II
| |
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM.” The following table presents the range of high and low intraday sales prices per share for the indicated quarterly periods in 2016 and 2015, as reported by the New York Stock Exchange:
|
| | | | | | | | |
| Quarter Ended | | High | | Low |
| December 31, 2016 | | $ | 43.09 |
| | $ | 30.25 |
|
| September 30, 2016 | | $ | 40.39 |
| | $ | 23.58 |
|
| June 30, 2016 | | $ | 35.60 |
| | $ | 17.04 |
|
| March 31, 2016 | | $ | 20.65 |
| | $ | 6.99 |
|
| | | | | |
| December 31, 2015 | | $ | 42.23 |
| | $ | 18.06 |
|
| September 30, 2015 | | $ | 45.98 |
| | $ | 18.21 |
|
| June 30, 2015 | | $ | 60.28 |
| | $ | 43.70 |
|
| March 31, 2015 | | $ | 53.31 |
| | $ | 31.01 |
|
PERFORMANCE GRAPH
The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2011,2014, and ending on December 31, 2016,2019, with the cumulative total returns of the Dow Jones U.S. Exploration and Production Index (“DJUSOS”), and the Standard & Poor’s 500 Stock Index.Index (“SPX”).
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS
The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the SEC.
Holders. As of February 15, 2017,6, 2020, the number of record holders of our common stock was 85.75. Based upon inquiry, management believes that the number of beneficial owners of our common stock is approximately 25,700.17,350.
Dividends. We have paid cash dividends to our stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in each of the years 2005 through 2016. We expect our practice of paying dividends on our common stock to continue, although the payment and amount of future dividends will continue to depend on our earnings, cash flow, capital requirements, financial condition, and other factors, including the discretion of our Board of Directors. In addition, the payment of dividends is subject to covenants in our Credit Agreement that limit our annual dividend payment to no more than $50.0 million per year. We are also subject to certain covenants under the indentures governing our Senior Notes and Senior Convertible Notes that restrict certain payments, including dividends; however, the first $6.5 million of dividends paid each year are not restricted by this covenant. Based on our current performance, we do not anticipate that these covenants will restrict future annual dividend payments in amounts not to exceed $0.10 per share of common stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $7.8 million, $6.8 million, and $6.7 million for the years ended December 31, 2016, 2015, and 2014, respectively.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2016,2019, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act.
|
| | | | | | | | | | | | |
| ISSUER PURCHASES OF EQUITY SECURITIES |
| | Total Number of Shares Purchased(1) | | Weighted Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Program | | Maximum Number of Shares that May Yet be Purchased Under the Program (2) |
January 1, 2016 - March 31, 2016 | 176 |
| | $ | 14.87 |
| | — |
| | 3,072,184 |
|
April 1, 2016 - June 30, 2016 | 1,053 |
| | $ | 28.99 |
| | — |
| | 3,072,184 |
|
July 1, 2016 - September 30, 2016 | 85,418 |
| | $ | 27.02 |
| | — |
| | 3,072,184 |
|
October 1, 2016 - October 31, 2016 | 343 |
| | $ | 39.37 |
| | — |
| | 3,072,184 |
|
November 1, 2016 - November 30, 2016 | — |
| | $ | — |
| | — |
| | 3,072,184 |
|
December 1, 2016 - December 31, 2016 | — |
| | $ | — |
| | — |
| | 3,072,184 |
|
Total October 1, 2016 - December 31, 2016 | 343 |
| | $ | 39.37 |
| | — |
| | 3,072,184 |
|
| Total | 86,990 |
| | $ | 27.07 |
| | — |
| | 3,072,184 |
|
PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
|
| | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased (1) | | Weighted Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Program | | Maximum Number of Shares that May Yet be Purchased Under the Program (2) |
01/01/2019 - 03/31/2019 | | 990 |
| | $ | 17.82 |
| | — |
| | 3,072,184 |
|
04/01/2019 - 06/30/2019 | | 154 |
| | $ | 14.91 |
| | — |
| | 3,072,184 |
|
07/01/2019 - 09/30/2019 | | 130,992 |
| | $ | 12.52 |
| | — |
| | 3,072,184 |
|
10/01/2019 - 12/31/2019 | | — |
| | $ | — |
| | — |
| | 3,072,184 |
|
| Total | | 132,136 |
| | $ | 12.56 |
| | — |
| | 3,072,184 |
|
| |
(1) | All shares purchased by us in 20162019 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs and PSUs deliveredRestricted Stock Units (“RSUs”) issued under the terms of grantsaward agreements granted under the SM Energy Equity Incentive Compensation Plan, (“Equityas amended and restated effective as of May 22, 2018 (the “Equity Plan”). |
| |
(2) | In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the datefiling of this filing,report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow,flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time. Please refer to Dividends above for a description of our dividend limitations. |
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected supplemental financial and operating data as of the dates and periodsor for the years indicated. The financial data for each of the five years presented werewas derived from our consolidated financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report.
| | | | Years Ended December 31, | As of or for the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (in millions, except per share data) | (in millions, except per share data) |
| Statement of Operations Data: | | | | | | | | | | |
| Statement of operations data: | | | | | | | | | | |
| Total operating revenues and other income | $ | 1,217.5 |
| | $ | 1,557.0 |
| | $ | 2,522.3 |
| | $ | 2,293.4 |
| | $ | 1,505.1 |
| $ | 1,590.1 |
| | $ | 2,067.1 |
| | $ | 1,129.4 |
| | $ | 1,217.5 |
| | $ | 1,557.0 |
|
| Net income (loss) | $ | (757.7 | ) | | $ | (447.7 | ) | | $ | 666.1 |
| | $ | 170.9 |
| | $ | (54.2 | ) | $ | (187.0 | ) | | $ | 508.4 |
| | $ | (160.8 | ) | | $ | (757.7 | ) | | $ | (447.7 | ) |
| Net income (loss) per share: | | | | | | | | | | | | | | | | | | |
| Basic | $ | (9.90 | ) | | $ | (6.61 | ) | | $ | 9.91 |
| | $ | 2.57 |
| | $ | (0.83 | ) | $ | (1.66 | ) | | $ | 4.54 |
| | $ | (1.44 | ) | | $ | (9.90 | ) | | $ | (6.61 | ) |
| Diluted | $ | (9.90 | ) | | $ | (6.61 | ) | | $ | 9.79 |
| | $ | 2.51 |
| | $ | (0.83 | ) | $ | (1.66 | ) | | $ | 4.48 |
| | $ | (1.44 | ) | | $ | (9.90 | ) | | $ | (6.61 | ) |
| Balance Sheet Data (at end of period): | | | | | | | | | |
| Cash dividends declared and paid per common share | | $ | 0.10 |
| | $ | 0.10 |
| | $ | 0.10 |
| | $ | 0.10 |
| | $ | 0.10 |
|
| Balance sheet data: | | Balance sheet data: | | | | | | | | |
| Total assets | $ | 6,393.5 |
| | $ | 5,621.6 |
| | $ | 6,483.1 |
| | $ | 4,678.1 |
| | $ | 4,179.0 |
| $ | 6,292.2 |
| | $ | 6,352.9 |
| | $ | 6,176.8 |
| | $ | 6,393.5 |
| | $ | 5,621.6 |
|
| Long-term debt: | | | | | | | | | | | | | | | | | | |
| Revolving credit facility | $ | — |
| | $ | 202.0 |
| | $ | 166.0 |
| | $ | — |
| | $ | 340.0 |
| $ | 122.5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 202.0 |
|
| Senior Notes, net of unamortized deferred financing costs | $ | 2,766.7 |
| | $ | 2,316.0 |
| | $ | 2,166.4 |
| | $ | 1,572.9 |
| | $ | 1,079.5 |
| $ | 2,453.0 |
| | $ | 2,448.4 |
| | $ | 2,769.7 |
| | $ | 2,766.7 |
| | $ | 2,316.0 |
|
| Senior Convertible Notes, net of unamortized discount and deferred financing costs | $ | 130.9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 157.3 |
| | $ | 147.9 |
| | $ | 139.1 |
| | $ | 130.9 |
| | $ | — |
|
| Cash dividends declared and paid per common share | $ | 0.10 |
| | $ | 0.10 |
| | $ | 0.10 |
| | $ | 0.10 |
| | $ | 0.10 |
| |
| | Supplemental Selected Financial and Operations Data | | | | |
| | For the Years Ended December 31, | As of or for the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Balance Sheet Data (in millions): | | | | | | | | | |
| Balance sheet data (in millions): | | Balance sheet data (in millions): | | | | | | | | |
| Total working capital (deficit) | $ | (190.5 | ) | | $ | 216.5 |
| | $ | (39.6 | ) | | $ | 8.4 |
| | $ | (201.0 | ) | $ | (219.4 | ) | | $ | (36.8 | ) | | $ | (10.1 | ) | | $ | (190.5 | ) | | $ | 216.5 |
|
| Total stockholders’ equity | $ | 2,497.1 |
| | $ | 1,852.4 |
| | $ | 2,286.7 |
| | $ | 1,606.8 |
| | $ | 1,414.5 |
| $ | 2,749.0 |
| | $ | 2,920.3 |
| | $ | 2,394.6 |
| | $ | 2,497.1 |
| | $ | 1,852.4 |
|
| Weighted-average common shares outstanding (in thousands): | Weighted-average common shares outstanding (in thousands): | | | | | | | Weighted-average common shares outstanding (in thousands): | | | | | | |
| Basic | 76,568 |
| | 67,723 |
| | 67,230 |
| | 66,615 |
| | 65,138 |
| 112,544 |
| | 111,912 |
| | 111,428 |
| | 76,568 |
| | 67,723 |
|
| Diluted | 76,568 |
| | 67,723 |
| | 68,044 |
| | 67,998 |
| | 65,138 |
| 112,544 |
| | 113,502 |
| | 111,428 |
| | 76,568 |
| | 67,723 |
|
| Reserves: | | | | | | | | | | | | | | | | | | |
| Oil (MMBbl) | 104.9 |
| | 145.3 |
| | 169.7 |
| | 126.6 |
| | 92.2 |
| 184.1 |
| | 175.7 |
| | 158.2 |
| | 104.9 |
| | 145.3 |
|
| Gas (Bcf) | 1,111.1 |
| | 1,264.0 |
| | 1,466.5 |
| | 1,189.3 |
| | 833.4 |
| 1,223.2 |
| | 1,321.8 |
| | 1,280.1 |
| | 1,111.1 |
| | 1,264.0 |
|
| NGLs (MMBbl) | 105.7 |
| | 115.4 |
| | 133.5 |
| | 103.9 |
| | 62.3 |
| 74.0 |
| | 107.4 |
| | 96.5 |
| | 105.7 |
| | 115.4 |
|
| MMBOE | 395.8 |
| | 471.3 |
| | 547.7 |
| | 428.7 |
| | 293.4 |
| |
| Production and Operations (in millions): | | | | | | | | | | |
MMBOE (1) | | 462.0 |
| | 503.4 |
| | 468.1 |
| | 395.8 |
| | 471.3 |
|
| | | | | | | | | | | |
| Production and operations (in millions): | | | | | | | | | | |
| Oil, gas, and NGL production revenue | $ | 1,178.4 |
| | $ | 1,499.9 |
| | $ | 2,481.5 |
| | $ | 2,199.6 |
| | $ | 1,473.9 |
| $ | 1,585.8 |
| | $ | 1,636.4 |
| | $ | 1,253.8 |
| | $ | 1,178.4 |
| | $ | 1,499.9 |
|
| Oil, gas, and NGL production expense | $ | 597.6 |
| | $ | 723.6 |
| | $ | 715.9 |
| | $ | 597.0 |
| | $ | 391.9 |
| $ | 500.7 |
| | $ | 487.4 |
| | $ | 507.9 |
| | $ | 597.6 |
| | $ | 723.6 |
|
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 790.7 |
| | $ | 921.0 |
| | $ | 767.5 |
| | $ | 822.9 |
| | $ | 727.9 |
| $ | 823.8 |
| | $ | 665.3 |
| | $ | 557.0 |
| | $ | 790.7 |
| | $ | 921.0 |
|
| General and administrative | $ | 126.4 |
| | $ | 157.7 |
| | $ | 167.1 |
| | $ | 149.6 |
| | $ | 119.8 |
| |
| Production Volumes: | | | | | | | | | | |
General and administrative (2) | | $ | 132.8 |
| | $ | 116.5 |
| | $ | 117.3 |
| | $ | 124.8 |
| | $ | 156.1 |
|
| Production volumes: | | | | | | | | | | |
| Oil (MMBbl) | 16.6 |
| | 19.2 |
| | 16.7 |
| | 13.9 |
| | 10.4 |
| 21.9 |
| | 18.8 |
| | 13.7 |
| | 16.6 |
| | 19.2 |
|
| Gas (Bcf) | 146.9 |
| | 173.6 |
| | 152.9 |
| | 149.3 |
| | 120.0 |
| 109.8 |
| | 103.2 |
| | 123.0 |
| | 146.9 |
| | 173.6 |
|
| NGLs (MMBbl) | 14.2 |
| | 16.1 |
| | 13.0 |
| | 9.5 |
| | 6.1 |
| 8.1 |
| | 7.9 |
| | 10.3 |
| | 14.2 |
| | 16.1 |
|
| MMBOE | 55.3 |
| | 64.2 |
| | 55.1 |
| | 48.3 |
| | 36.5 |
| |
MMBOE (1) | | 48.3 |
| | 43.9 |
| | 44.5 |
| | 55.3 |
| | 64.2 |
|
| | | | | | | | | | | |
| Realized price, before the effect of derivative settlements: | | | | | | | | | | Realized price, before the effect of derivative settlements: | | | | | | |
| Oil (per Bbl) | $ | 36.85 |
| | $ | 41.49 |
| | $ | 80.97 |
| | $ | 91.19 |
| | $ | 85.45 |
| $ | 54.10 |
| | $ | 56.80 |
| | $ | 47.88 |
| | $ | 36.85 |
| | $ | 41.49 |
|
| Gas (per Mcf) | $ | 2.30 |
| | $ | 2.57 |
| | $ | 4.58 |
| | $ | 3.93 |
| | $ | 2.98 |
| $ | 2.39 |
| | $ | 3.43 |
| | $ | 3.00 |
| | $ | 2.30 |
| | $ | 2.57 |
|
| NGLs (per Bbl) | $ | 16.16 |
| | $ | 15.92 |
| | $ | 33.34 |
| | $ | 35.95 |
| | $ | 37.61 |
| $ | 17.26 |
| | $ | 27.22 |
| | $ | 22.35 |
| | $ | 16.16 |
| | $ | 15.92 |
|
| Per BOE | | $ | 32.84 |
| | $ | 37.27 |
| | $ | 28.20 |
| | $ | 21.32 |
| | $ | 23.36 |
|
| Expense per BOE: | | | | | | | | | | | | | | | | | | |
| Lease operating expense | $ | 3.51 |
| | $ | 3.73 |
| | $ | 4.28 |
| | $ | 4.49 |
| | $ | 4.54 |
| $ | 4.67 |
| | $ | 4.74 |
| | $ | 4.43 |
| | $ | 3.51 |
| | $ | 3.73 |
|
| Transportation costs | $ | 6.16 |
| | $ | 6.02 |
| | $ | 6.11 |
| | $ | 5.34 |
| | $ | 3.81 |
| $ | 3.88 |
| | $ | 4.36 |
| | $ | 5.48 |
| | $ | 6.16 |
| | $ | 6.02 |
|
| Production taxes | $ | 0.94 |
| | $ | 1.13 |
| | $ | 2.13 |
| | $ | 2.19 |
| | $ | 2.00 |
| $ | 1.35 |
| | $ | 1.52 |
| | $ | 1.18 |
| | $ | 0.94 |
| | $ | 1.13 |
|
| Ad valorem tax expense | $ | 0.21 |
| | $ | 0.39 |
| | $ | 0.46 |
| | $ | 0.33 |
| | $ | 0.39 |
| $ | 0.48 |
| | $ | 0.48 |
| | $ | 0.34 |
| | $ | 0.21 |
| | $ | 0.39 |
|
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 14.30 |
| | $ | 14.34 |
| | $ | 13.92 |
| | $ | 17.02 |
| | $ | 19.95 |
| $ | 17.06 |
| | $ | 15.15 |
| | $ | 12.53 |
| | $ | 14.30 |
| | $ | 14.34 |
|
| General and administrative | $ | 2.29 |
| | $ | 2.46 |
| | $ | 3.03 |
| | $ | 3.09 |
| | $ | 3.28 |
| |
| Statement of Cash Flow Data (in millions): | | | | | | | | | | |
| Provided by operating activities | $ | 552.8 |
| | $ | 978.4 |
| | $ | 1,456.6 |
| | $ | 1,338.5 |
| | $ | 922.0 |
| |
| Used in investing activities | $ | (1,870.6 | ) | | $ | (1,144.6 | ) | | $ | (2,478.7 | ) | | $ | (1,192.9 | ) | | $ | (1,457.3 | ) | |
| Provided by financing activities | $ | 1,327.2 |
| | $ | 166.2 |
| | $ | 740.0 |
| | $ | 130.7 |
| | $ | 422.1 |
| |
General and administrative (2) | | $ | 2.75 |
| | $ | 2.65 |
| | $ | 2.64 |
| | $ | 2.26 |
| | $ | 2.43 |
|
| Statement of cash flows data (in millions): | | | | | | | | | | |
Provided by operating activities (2) | | $ | 823.6 |
| | $ | 720.6 |
| | $ | 515.4 |
| | $ | 552.8 |
| | $ | 990.8 |
|
Used in investing activities (2) | | $ | (1,013.3 | ) | | $ | (587.9 | ) | | $ | (201.5 | ) | | $ | (1,867.6 | ) | | $ | (1,144.6 | ) |
Provided by (used in) financing activities (2) | | $ | 111.8 |
| | $ | (368.7 | ) | | $ | (12.3 | ) | | $ | 1,327.2 |
| | $ | 153.7 |
|
| |
ITEM 7.(1) | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSAmounts may not calculate due to rounding. |
| |
(2) | As a result of adopting new accounting standards in prior periods, certain prior period amounts have been reclassified to conform to the current period presentation on the consolidated financial statements. |
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements in Part I, Items 1 and 2 section of this report for important information about these types of statements.
Overview of the Company
General Overview
We are an independentOur purpose is to make people’s lives better by responsibly producing energy company engagedsupplies, contributing to energy security and prosperity, and having a positive impact in the acquisition, exploration, development,communities where we live and production of oil, gas, and NGLs in onshore North America. We currently have development positions inwork. Our long-term vision for the Midland Basin, Eagle Ford shale, and Bakken/Three Forks resource plays. Our strategic objectiveCompany is to becomesustainably grow value for all of our stakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top tier assets. During 2016, we cored upAt present, our investment portfolio through several acquisitionsis focused on high quality oil and gas producing assets in the state of Texas, specifically in the Midland Basin where we expanded our footprint to approximately 82,550 net acres. of West Texas and in South Texas.
2019 Financial and Operational Highlights
We were able to accomplish this through the divestiture of non-core assetsremain focused on maximizing returns and through successful financing transactions. Our Midland Basin assets, as well as our operated Eagle Ford shale assets, have high operating margins and significant opportunities for additional economic investment. We seek to maximizeincreasing the value of our top tier Midland Basin and South Texas assets. We expect to do this through continued development optimization and delineation. We believe our assets provide significant production growth potential and strong returns that are capable of increasing internally generated cash flows and support our priorities of improving credit metrics and maintaining strong financial flexibility.
Financial and Operational Results. Average net daily production for the year ended December 31, 2019, was 132.3 MBOE, compared with 120.3 MBOE for the same period in 2018. This increase was primarily driven by a 25 percent increase in production volumes from our Midland Basin assets. Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased five percent, 30 percent, and 37 percent, respectively, for the year ended December 31, 2019, compared with the year ended December 31, 2018. As a result of decreased realized prices, oil, gas, and NGL production revenue decreased three percent to $1.59 billion for the year ended December 31, 2019, compared with $1.64 billion for 2018. The decrease in oil, gas, and NGL production revenue due to pricing was largely offset by increased production. We recorded a net derivative loss of $97.5 million for the year ended December 31, 2019, compared to a net derivative gain of $161.8 million for the same period in 2018. Included within these derivative amounts is a gain of $39.2 million on derivative contracts that settled during the year ended December 31, 2019, and a loss of $135.8 million for the same period in 2018. Overall financial and operational activities during the year ended December 31, 2019, resulted in the following:
| |
| • | net loss of $187.0 million, or $1.66 per diluted share, for the year ended December 31, 2019, compared with net income of $508.4 million, or $4.48 per diluted share, for the year ended December 31, 2018. Please refer to Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion regarding the components of net income (loss) for each period presented; |
| |
| • | net cash provided by operating activities was $823.6 million for the year ended December 31, 2019, compared with $720.6 million in 2018, which was an increase of 14 percent year-over-year. Please refer to Analysis of Cash Flow Changes Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion; and |
| |
| • | adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2019, was $993.4 million, compared with $900.4 million for the same period in 2018. Please refer to Non-GAAP Financial Measuresbelow for additional discussion, including our definition of adjusted EBITDAX and reconciliations to our net income (loss) and net cash provided by operating activities. |
Total estimated proved reserves as of December 31, 2019 decreased eight percent from December 31, 2018 to 462.0 MMBOE, of which, 56 percent were liquids (oil and NGLs) and 53 percent were characterized as proved developed. During 2019, we added 98.4 MMBOE through industry leading technology applicationour Midland Basin and outstandingSouth Texas development activities. The 2019 results were partially offset by downward revisions of 94.7 MMBOE primarily resulting from lower commodity prices. Lower commodity prices were also the primary factor in our decreased estimated proved reserve life index, which was 9.6 years at December 31, 2019, compared to 11.5 years at December 31, 2018. Please refer to Reservesin Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $4.1 billion as of December 31, 2019, compared with $4.7 billion as of December 31, 2018, which was a decrease of 12 percent year-over-year. Please refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.
Operational Activities. The performance of the RockStar area of our Midland Basin position continues to exceed our pre-acquisition expectations and was key to driving significant growth in our operating margin and cash flows from operations in 2019 due to the high percentage of oil that these wells produce. Our operational execution. execution and development strategy in this region have resulted in strong well performance due to enhanced completion designs and our ability to drill longer laterals given the increasingly contiguous nature of our acreage position as a result of successful infill leasing and acreage trades. Efficiency in completions and operations
continued in 2019, as a large portion of our water transportation and disposal needs continue to be satisfied by the water facilities we operate in a core area of our RockStar acreage. We also continued to increase our use of locally sourced sand in our well completions, which has resulted in further cost savings and improved returns for our program.
Our portfolio is comprisedMidland Basin program averaged six drilling rigs and three completion crews during 2019. We completed 123 gross (111 net) operated wells during 2019 and increased production volumes year-over-year by 25 percent to 26.3 MMBOE, 78 percent of properties with prospectivewhich was oil. 82 percent of our total 2019 costs incurred in our oil and gas producing activities was incurred in our Midland Basin program. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on delineating and developing the Lower Spraberry and Wolfcamp A and B shale intervals.
Our South Texas program averaged one drilling opportunitiesrig and unconventional resource prospects, which we believe provideone completion crew during 2019. We completed 31 gross (20 net) wells during 2019. Total production for long-term production2019 was 22.0 MMBOE, a one percent increase from 2018. 16 percent of our total 2019 costs incurred in our oil and reserves growth. Wegas producing activities was incurred in our South Texas program. Drilling and completion activities in South Texas continue to focus on achieving high full-cycle economic returnsdeveloping the Eagle Ford shale formation and delineating the Austin Chalk formation.
Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to our joint development agreement. The agreement provided that the third party would carry substantially all drilling and completion costs and receive a majority of the working and revenue interest in these wells until certain payout thresholds are reached. This arrangement allowed us to leverage third-party capital to prove up the value of our Eagle Ford North area, while also allowing us to test cutting edge technology, capture additional technical data, and satisfy certain lease obligations. All wells subject to this agreement were drilled and completed as of December 31, 2019.
The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the year ended December 31, 2019: |
| | | | | | | | | | | | | | | | | |
| | Midland Basin | | South Texas | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Wells drilled but not completed at December 31, 2018 | 61 |
| | 55 |
| | 29 |
| | 23 |
| | 90 |
| | 78 |
|
| Wells drilled | 113 |
| | 104 |
| | 25 |
| | 20 |
| | 138 |
| | 124 |
|
| Wells completed | (123 | ) | | (111 | ) | | (31 | ) | | (20 | ) | | (154 | ) | | (131 | ) |
Other (1) | — |
| | — |
| | (2 | ) | | (2 | ) | | (2 | ) | | (2 | ) |
| Wells drilled but not completed at December 31, 2019 | 51 |
| | 48 |
| | 21 |
| | 21 |
| | 72 |
| | 69 |
|
| |
(1) | Includes adjustments related to previously drilled wells that we no longer intend to complete. |
Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows: |
| | | |
| | For the Year Ended |
| | December 31, 2019 |
| | (in millions) |
| Development costs | $ | 914.0 |
|
| Exploration costs | 115.0 |
|
| Acquisitions | |
| Proved properties | (0.3 | ) |
| Unproved properties | 11.6 |
|
Total, including asset retirement obligations (1) | $ | 1,040.2 |
|
Note: Total may not calculate due to rounding.
| |
(1) | Please refer to the caption Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report. |
All of our development and exploration costs were incurred in our Midland Basin and South Texas programs for the year ended December 31, 2019. Of these costs, $848.6 million was directed to the development of our Midland Basin assets, which resulted in 104 net wells drilled and 111 net wells completed. Comparatively, for the year ended December 31, 2018, $1.1 billion was directed to the development of our Midland Basin assets, which resulted in 117 net wells drilled and 104 net wells completed. Costs incurred for acquisitions during the year related to transactions in the Midland Basin, as well as payments made to extend certain lease terms and to acquire new leases. Please refer to Operational Activities above and Acquisition Activity below for additional information on our investmentsregional activities.
Production Results. The table below presents the disaggregation of our production by product type for each of our operating regions for the year ended December 31, 2019: |
| | | | | | | | |
| | Midland Basin | | South Texas | | Total |
| Production: | | | | | |
| Oil (MMBbl) | 20.5 |
| | 1.3 |
| | 21.9 |
|
| Gas (Bcf) | 34.4 |
| | 75.4 |
| | 109.8 |
|
| NGLs (MMBbl) | — |
| | 8.1 |
| | 8.1 |
|
| Equivalent (MMBOE) | 26.3 |
| | 22.0 |
| | 48.3 |
|
| Avg. daily equivalents (MBOE/d) | 72.0 |
| | 60.3 |
| | 132.3 |
|
| Relative percentage | 54 | % | | 46 | % | | 100 | % |
Note: Amounts may not calculate due to rounding.
Production increased 10 percent for the year ended December 31, 2019, compared with 2018. The increase in overall production volumes was primarily attributable to our Midland Basin assets, which had an increase in production volumes of 25 percent for the year ended December 31, 2019, compared with 2018. Please refer toA Year-to-Year Overview of Selected Production and maintaining a simple, strong balance sheet.Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion on production.
Acquisition Activity. During 2019, while no significant acquisition activity occurred, we completed several non-monetary acreage trades of undeveloped properties located in Howard, Martin, and Midland Counties, Texas, to continue maximizing our operational efficiencies in our Midland Basin program. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitionsin Part II, Item 8 of this report for additional discussion.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. We sell the majority of our gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold at the wellhead, we also receive additional value for the higher energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS daily settlement prices, adjusted for processing, transportation, and location differentials. Our oil is sold using the calendar month average of the NYMEX WTI daily contract settlement prices, excluding weekends, during the month of production, adjusted for quality, transportation, American Petroleum Institute (“API”) gravity, and location differentials. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effects of derivative settlements, unless otherwise indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products.
The following table summarizes commodity price data, as well as the effects of derivative settlements, as further discussed under the caption Derivative Activity below, for the years ended December 31, 2016, 2015,2019, 2018, and 2014:2017:
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Crude Oil (per Bbl): | | | | | | |
| Oil (per Bbl): | | | | | | |
| Average NYMEX contract monthly price | $ | 43.32 |
| | $ | 48.68 |
| | $ | 93.03 |
| $ | 57.03 |
| | $ | 64.77 |
| | $ | 50.95 |
|
| Realized price, before the effect of derivative settlements | $ | 36.85 |
| | $ | 41.49 |
| | $ | 80.97 |
| $ | 54.10 |
| | $ | 56.80 |
| | $ | 47.88 |
|
| Effect of oil derivative settlements | $ | 14.63 |
| | $ | 18.85 |
| | $ | 1.71 |
| $ | (0.90 | ) | | $ | (3.67 | ) | | $ | (2.28 | ) |
| | | | | | | | | | | |
| Natural Gas: | | | | | | |
| Gas: | | | | | | |
| Average NYMEX monthly settle price (per MMBtu) | $ | 2.46 |
| | $ | 2.61 |
| | $ | 4.35 |
| $ | 2.63 |
| | $ | 3.09 |
| | $ | 3.11 |
|
| Realized price, before the effect of derivative settlements (per Mcf) | $ | 2.30 |
| | $ | 2.57 |
| | $ | 4.58 |
| $ | 2.39 |
| | $ | 3.43 |
| | $ | 3.00 |
|
Effect of natural gas derivative settlements (per Mcf) (1) | $ | 0.64 |
| | $ | 0.71 |
| | $ | (0.18 | ) | |
| Effect of gas derivative settlements (per Mcf) | | $ | 0.21 |
| | $ | (0.12 | ) | | $ | 0.72 |
|
| | | | | | | | | | | |
| NGLs (per Bbl): | | | | | | | | | | |
Average OPIS price (2)(1) | $ | 19.98 |
| | $ | 19.76 |
| | $ | 38.93 |
| $ | 22.34 |
| | $ | 32.96 |
| | $ | 27.63 |
|
| Realized price, before the effect of derivative settlements | $ | 16.16 |
| | $ | 15.92 |
| | $ | 33.34 |
| $ | 17.26 |
| | $ | 27.22 |
| | $ | 22.35 |
|
| Effect of NGL derivative settlements | $ | (0.60 | ) | | $ | 1.69 |
| | $ | 0.84 |
| $ | 4.43 |
| | $ | (6.78 | ) | | $ | (3.44 | ) |
| |
(1) | Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, of early settlements of futures contracts as a result of divesting assets in our Mid-Continent region. These early settlements increased the effect of derivative settlements by $0.09 per Mcf and $0.04 per Mcf for the years ended December 31, 2015, and 2014, respectively. |
| |
(2)
| Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix. |
While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products.
We expect future benchmark prices for oil, gas, and NGLs to continue to be volatile.volatile due to uncertainty in global supply and demand. In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in allvarious regions of the world as well as the relative strength of the U.S.United States dollar compared to other currencies. Oil markets continue to be unstable as a result of over-supply with globalIncreased demand remaining the biggest source of uncertainty for future prices. The recent increase in oil prices is primarily attributable to the Organization of Petroleum Exporting Countries (OPEC)liquefied natural gas and non-OPEC exporting countries agreeing to cut production in 2017, although there is still uncertainty as to whether these cuts will actually occur or be sustained. Drilling activity in the U.S. has increased in recent months putting continued downward pressure on oil prices in the near term.
Natural gas pricing increased during 2016, partially as a result of demand growth from gas fired power generation and both LNG exports and exports to Mexico exceeding prior expectations. We expect pricesare expected to remain near current levels in the near term as drilling rigs in operation have increased in recent months leading to increased supply, which we expect will be offset by continued demand growth from LNG exports and exports to Mexico. We also expect prices to fluctuate with changes in demand resulting from the weather.
help balance natural gas supply. NGL prices have recovered in recent months duemay continue to oil and natural gas price recovery. We expect NGL prices to remain near current levels through 2017, asbenefit from increased demand from export and petrochemical markets iswhile being offset by increased drilling activity. Our realized prices at local sales points may also be affected by infrastructure capacity in the area of our operations and beyond.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed under the table above) as of February 15, 2017,6, 2020, and December 31, 2016:
| | | | As of February 15, 2017 | | As of December 31, 2016 | As of February 6, 2020 | | As of December 31, 2019 |
| NYMEX WTI oil (per Bbl) | $ | 54.53 |
| | $ | 56.01 |
| $ | 51.46 |
| | $ | 59.01 |
|
| NYMEX Henry Hub gas (per MMBtu) | $ | 3.25 |
| | $ | 3.63 |
| $ | 2.15 |
| | $ | 2.28 |
|
| OPIS NGLs (per Bbl) | $ | 27.39 |
| | $ | 27.14 |
| $ | 18.09 |
| | $ | 20.00 |
|
We use financial derivative instruments as part of our financial risk management program. We have a financial risk
management policy governing our use of derivatives.derivatives, and decisions regarding entering into derivative commodity contracts are overseen by a financial risk management committee consisting of senior executive officers and finance personnel. The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and our ability to enter into favorable derivative commodity contracts. With our current derivative commodity contracts, we believe we have partially reduced our exposure to volatility in commodity prices and location differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor for a portion of our oil and gas production.
Please refer to Note 10 -– Derivative Financial Instrumentsin Part II, Item 8 of this report and the caption titled to Commodity Price Risk in Overview of Liquidity and Capital Resourcesbelow for additional information regarding our oil, gas, and NGL derivatives.
Due to the depressed commodity price environment in recent years, and our belief that commodity prices will remain near current levels, we cored up our portfolio in 2016 through various acquisitions and divestitures. As noted below, we expect additional divestitures in 2017, proceeds from which will partially fund the development of our recently acquired Midland Basin assets, as well as pay down debt should market conditions be favorable.Outlook
Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
|
| | | |
| | For the Year Ended |
| | December 31, 2016 |
| | (in millions) |
| Development costs | $ | 595.3 |
|
| Exploration costs | 118.2 |
|
| Acquisitions | |
| Proved properties | 201.7 |
|
| Unproved properties | 2,458.7 |
|
Total, including asset retirement obligation (1) | $ | 3,373.9 |
|
| |
(1)
| Please refer to the section Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information in Part II, Item 8 of this report.
|
Outside of acquisition activity in the Permian region, our costs relating to exploration and development activities were incurred evenly across our core development programs in the Eagle Ford shale, Midland Basin, and Bakken/Three Forks for the year ended December 31, 2016.
Acquisition Activity:
On October 4, 2016, we closed our Rock Oil Acquisition in Howard County, Texas, for an adjusted purchase price of approximately $991.0 million, subject to customary post-closing adjustments.
On December 21, 2016, we closed our QStar Acquisition in Howard and Martin Counties, Texas, for an adjusted purchase price of approximately $1.6 billion, subject to customary post-closing adjustments.
These acquisitions significantly increased our footprint in the Midland Basin, with the acquired acreage having producing and prospective intervals in the Lower and Middle Spraberry and Wolfcamp A and B shale formations.
In order to fund our 2016 acquisition activity and a portion of the future development of acquired assets, we divested of assets in 2016, have additional divestitures in process, and executed certain financing transactions, as discussed below.
Divestiture Activity:
On December 1, 2016, we completed our Raven/Bear Den asset divestiture for net divestiture proceeds of $756.2 million, subject to customary post-closing adjustments, as discussed in Note 3 – Acquisitions, Divestitures, and Assets Held for Sale in Part II, Item 8 of this report.
During the third quarter of 2016, we closed the divestitures of certain non-core properties in southeast New Mexico and in the Williston and Powder River Basins for total net divestiture proceeds of $165.2 million, subject to customary post-closing adjustments.
We began marketing our outside-operated Eagle Ford shale assets during the third quarter of 2016. Subsequent to December 31, 2016, we executed a definitive sales agreement for a gross purchase price of $800 million, subject to customary purchase price adjustments, with the sale expected to close in the first quarter of 2017.
Subsequent to December 31, 2016, we announced our plans to sell our remaining Williston Basin assets in Divide County, North Dakota.
Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale Outlookin Part II,I, Item 81 of this report for additional discussion.
Equity Offerings:
On August 12, 2016, we issued approximately 18.4 million sharesdiscussion of common stock in a public offeringour financing and capital plans for net proceeds of $530.9 million.
On December 7, 2016, we issued an additional approximately 10.9 million shares of common stock in a public offering for net proceeds of $403.2 million.
On December 21, 2016, to partially fund the QStar Acquisition, we issued to the sellers approximately 13.4 million shares of common stock valued at $437.2 million.
Please2020, and refer to Note 15 - Equity in Part II, Item 8 of this report for additional discussion.
Long-Term Debt:
Senior Convertible Notes. On August 12, 2016, we issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due 2021 for net proceeds of $166.6 million. In conjunction with this issuance, we paid $24.2 million for capped call transactions, which are generally expected to reduce the potential dilution and/or partially offset any cash payments required upon conversion.
2026 Notes. On September 12, 2016, we issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026 and received net proceeds of $491.6 million.
Repurchased Notes. During the first quarter of 2016, we repurchased a total of $46.3 million in aggregate principal amount of certain of our Senior Notes in open market transactions for a settlement amount of $29.9 million, excluding interest, which resulted in a net gain on extinguishment of debt of approximately $15.7 million.
Credit Agreement. Our borrowing base and aggregate lender commitments changed throughout 2016 due to the normal redetermination process, amendments to the Credit Agreement, and significant transactions that occurred. As of December 31, 2016, our borrowing base and aggregate lender commitments under the Credit Agreement were $1.17 billion.
Please refer to Overview of Liquidity and Capital Resources below and Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion.
2016 Operational Activity and Financial Results
Operational Activities. During 2016, we focused on coring up our portfolio to high-grade assets and build long-term inventory. Please refer to the table below summarizing our operated drilling and completion activities for the year ended December 31, 2016. We incurred capital expenditures, excluding asset acquisitions, below adjusted EBITDAX in 2016.
In our Midland Basin program, we began operating one drilling rig in early 2016 and added a second drilling rig in the second quarter of 2016, both focused on developing the Wolfcamp and Spraberry shale intervals on our Sweetie Peck property in Upton County, Texas. We closed our Rock Oil and QStar acquisitions during the fourth quarter of 2016 and added two operated rigs on the acquired acreage. During the third quarter of 2016, we sold our non-core assets in southeast New Mexico.
In our operated Eagle Ford shale program, we began 2016 operating three drilling rigs and released all three rigs during the year. In addition, we utilized one frac crew through the third quarter of 2016. In 2016, our capital was primarily spent on wells that were drilled but not completed at year-end 2015 and to meet lease obligations.
In our outside-operated Eagle Ford shale program, the operator began 2016 running one drilling rig, which was released in the first quarter of 2016 with no further drilling activity for the remainder of the year. The operator completed 69 gross (11 net) wells during 2016, all of which were completed prior to mid-year. Our outside-operated Eagle Ford shale assets, including the associated midstream assets, were held for sale as of December 31, 2016, with the sale expected to close in the first quarter of 2017. Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale in Part II, Item 8 of this report for additional information.
In our Bakken/Three Forks program, we started the year operating two drilling rigs. We released one drilling rig during the second quarter of 2016 and ran the second rig through November 2016. During the third quarter of 2016, we sold non-core Williston Basin assets, and on December 1, 2016, we completed the divestiture of our Raven/Bear Den assets. Subsequent to December 31, 2016, we announced our plans to sell our remaining Williston Basin assets in Divide County, North Dakota with closing expected by mid-year 2017.
In our Powder River Basin program, we began 2016 operating one drilling rig and released the rig during the first quarter. We added a drilling rig during the third quarter of 2016 for activities under an acquisition and development funding agreement with a third party, under which our costs to drill and complete a specified number of initial wells are being carried by the third party.
The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs during the year ended December 31, 2016. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Eagle Ford Shale | | Midland Basin | | Bakken/Three Forks | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Wells drilled but not completed at December 31, 2015 | 76 |
| | 76 |
| | 9 |
| | 9 |
| | 47 |
| | 39 |
| | 132 |
| | 124 |
|
| Wells drilled | 16 |
| | 16 |
| | 27 |
| | 25 |
| | 24 |
| | 23 |
| | 67 |
| | 64 |
|
Wells acquired (1) | — |
| | — |
| | 11 |
| | 11 |
| | — |
| | — |
| | 11 |
| | 11 |
|
Wells completed (2) | (45 | ) | | (45 | ) | | (30 | ) | | (28 | ) | | (51 | ) | | (45 | ) | | (126 | ) | | (118 | ) |
Wells drilled but not completed at December 31, 2016 (3) | 47 |
| | 47 |
| | 17 |
| | 17 |
| | 20 |
| | 17 |
| | 84 |
| | 81 |
|
| |
(1)
| Represents in-progress wells acquired in the Rock Oil and QStar acquisitions. In all cases, the sellers initiated the drilling of the well. Of these acquired in-progress wells, we completed six gross and net wells after the closing dates and before year-end 2016.
|
| |
(2)
| Of the wells we completed in 2016, 11 gross (eight net) wells were divested in the fourth quarter of 2016. |
| |
(3)
| Subsequent to December 31, 2016, we announced plans to sell our remaining Bakken/Three Forks assets in Divide County, North Dakota. |
Production Results. The table below provides a regional breakdown of our production for 2016: |
| | | | | | | | | | | |
| | South Texas & Gulf Coast | | Permian | | Rocky Mountain | | Total (1) |
| Production: | | | | | | | |
| Oil (MMBbl) | 5.5 |
| | 2.7 |
| | 8.3 |
| | 16.6 |
|
| Gas (Bcf) | 130.9 |
| | 6.0 |
| | 10.0 |
| | 146.9 |
|
| NGLs (MMBbl) | 13.9 |
| | — |
| | 0.3 |
| | 14.2 |
|
Equivalent (MMBOE) (1) | 41.2 |
| | 3.8 |
| | 10.3 |
| | 55.3 |
|
| Avg. Daily Equivalents (MBOE/d) | 112.6 |
| | 10.2 |
| | 28.2 |
| | 151.0 |
| Relative percentage | 74 | % | | 7 | % | | 19 | % | | 100 | % |
| |
(1)
| Amounts may not calculate due to rounding. |
Production decreased for the year ended December 31, 2016, compared with the same period in 2015, driven by the reduction in our drilling and completion activity and the divestitures of properties in our Rocky Mountain and Permian regions in the last half of 2016, as well as the impact of the sale of our Mid-Continent properties in the second quarter of 2015. Please refer to the tableabove for a summary of wells drilled, acquired, and completed in our operated programs during the year ended December 31, 2016.
Please refer toComparison of Financial Results and Trends Between 2016 and 2015 and Between 2015 and 2014and A Year-to-Year Overview of Selected Production and Financial Information, Including Trends below for additional discussion on production.
Financial Results for 2016
We recorded a net loss of $757.7 million, or $9.90 per diluted share, for the year ended December 31, 2016. This compares with a net loss of $447.7 million, or $6.61 per diluted share, for the year ended December 31, 2015. The net loss in 2016 was driven largely by decreased production revenue due to sustained low commodity prices, discussed in detail above and a decrease in the fair value of commodity derivative contracts. Additionally, we recorded proved and unproved property impairments of $354.6 million and $80.4 million, respectively, for the year ended December 31, 2016. These impairments were largely due to the continued decline in commodity prices in early 2016 impacting our outside-operated Eagle Ford shale assets and negative reserve performance revisions on our Powder River Basin assets at year-end 2016. Please refer to the caption Comparison of Financial Results and Trends Between 2016 and 2015 and Between 2015 and 2014 below for additional discussion regarding the components of net income (loss).
At year-end 2016, we had estimated proved reserves of 395.8 MMBOE, of which 53 percent were liquids (oil and NGLs) and 53 percent were characterized as proved developed. During 2016, we added 108.2 MMBOE through our drilling program and acquired 15.5 MMBOE, as discussed above. We divested of 47.7 MMBOE of proved reserves and had negative revisions totaling 96.2 MMBOE, consisting of a negative 18.1 MMBOE performance revision, a negative 35.1 MMBOE price revision due to the decline in commodity prices in 2016, and 43.0 MMBOE of proved undeveloped reserves removed due to the five-year rule. Our proved reserve life index decreased slightly to 7.2 years in 2016. Please refer to Reserves included in Part I, Items 1 and 2 of this report for additional discussion.
The standardized measure of discounted future net cash flows was $1.2 billion as of December 31, 2016, compared with $1.8 billion as of December 31, 2015. Please refer to the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report.
We had net cash provided by operating activities of $552.8 million for the year ended December 31, 2016, compared with $978.4 million for the year ended December 31, 2015, which was a decrease of 43 percent year-over-year. Please refer to Analysis of Cash Flow Changes Between 2016 and 2015 and Between 2015 and 2014 below for additional discussion.
Adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2016, was $790.8 million, compared with $1.1 billion for the same period in 2015. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and a reconciliation of our net income (loss) and net cash provided by operating activities to adjusted EBITDAX.
Outlook for 2017
Our priorities for 2017 are to:
demonstrate the value of our 2016 acquisitions in the Midland Basin;
generate high margin production growth from our operated acreage positions in the Midland Basin and Eagle Ford shale;
successfully execute the sale of our outside-operated Eagle Ford shale and Divide County assets; and
reduce our outstanding debt.
Our capital program for 2017, excluding acquisitions, is expected to be approximately $875 million. By concentrating our capital on the highest return programs and operating at strong performance levels, we believe we will generate higher company-wide margins, cash flow growth, and value creation for our stockholders going forward.
In our Midland Basin program, we entered 2017 operating four drilling rigs and plan to increase to six drilling rigs in early 2017 and continue with six drilling rigs in operation through the year. In 2017, our focus will be on developing the Wolfcamp and Spraberry shale intervals on our Sweetie Peck property in Upton County, Texas, as well as delineating and developing the Lower and Middle Spraberry and Wolfcamp A and B shale intervals on our recently acquired acreage in Howard and Martin Counties, Texas. Subsequent to December 31, 2016, we acquired approximately 2,900 additional net acres in Howard County, Texas for approximately $60.0 million.
In our operated Eagle Ford shale program, we began operating a drilling rig in February 2017, and plan to run a one to two rig program throughout 2017. We will remain focused on reducing our drilled but not completed well count and meeting lease obligations.
We expect the sale of our outside-operated Eagle Ford shale assets, including our ownership interest in related midstream assets, to close in the first quarter of 2017 under the executed definitive agreement for a gross purchase price of $800 million, subject to customary closing adjustments.
Subsequent to December 31, 2016, we announced our plans to sell our remaining Bakken/Three Forks assets in Divide County, North Dakota. We expect this sale to be completed by mid-2017.
In our Powder River Basin program, we intend to continue running one drilling rig in 2017 under an acquisition and development funding agreement with a third party, in which the third party is carrying our drilling and completion costs, as discussed above.
Please refer to Overview of LiquidityandCapital Resources below for additional discussion on how we expect to fund our 20172020 capital program.
Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the quarterthree months ended December 31, 2016,2019, and the immediately preceding three quarters. A detailed discussion follows.
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended |
| | December 31, | | September 30, | | June 30, | | March 31, |
| | 2019 | | 2019 | | 2019 | | 2019 |
| | (in millions) |
| Production (MMBOE) | 12.8 |
| | 12.4 |
| | 12.4 |
| | 10.7 |
|
| Oil, gas, and NGL production revenue | $ | 449.0 |
| | $ | 389.4 |
| | $ | 406.9 |
| | $ | 340.5 |
|
| Oil, gas, and NGL production expense | $ | 127.3 |
| | $ | 129.0 |
| | $ | 123.1 |
| | $ | 121.3 |
|
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 228.7 |
| | $ | 211.1 |
| | $ | 206.3 |
| | $ | 177.7 |
|
| Exploration | $ | 17.7 |
| | $ | 11.6 |
| | $ | 10.9 |
| | $ | 11.3 |
|
| General and administrative | $ | 37.2 |
| | $ | 32.6 |
| | $ | 30.9 |
| | $ | 32.1 |
|
| Net income (loss) | $ | (102.1 | ) | | $ | 42.2 |
| | $ | 50.4 |
| | $ | (177.6 | ) |
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended |
| | December 31, | | September 30, | | June 30, | | March 31, |
| | 2016 | | 2016 | | 2016 | | 2016 |
| | (in millions, except for production data) |
| Production (MMBOE) | 13.4 |
| | 14.2 |
| | 14.3 |
| | 13.4 |
|
| Oil, gas, and NGL production revenue | $ | 346.3 |
| | $ | 329.2 |
| | $ | 291.1 |
| | $ | 211.8 |
|
| Oil, gas, and NGL production expense | $ | 151.9 |
| | $ | 152.5 |
| | $ | 148.6 |
| | $ | 144.5 |
|
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 171.6 |
| | $ | 194.0 |
| | $ | 211.0 |
| | $ | 214.2 |
|
| Exploration | $ | 23.7 |
| | $ | 13.5 |
| | $ | 13.2 |
| | $ | 15.3 |
|
| General and administrative | $ | 33.3 |
| | $ | 32.7 |
| | $ | 28.2 |
| | $ | 32.2 |
|
| Net income (loss) | $ | (200.9 | ) | | $ | (40.9 | ) | | $ | (168.7 | ) | | $ | (347.2 | ) |
Note: Amounts may not calculate due to rounding.
Selected Performance Metrics:Metrics
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended |
| | December 31, | | September 30, | | June 30, | | March 31, |
| | 2016 | | 2016 | | 2016 | | 2016 |
| Average net daily production equivalent (MBOE per day) | 145.6 |
| | 153.9 |
| | 157.2 |
| | 147.5 |
|
| Lease operating expense (per BOE) | $ | 3.67 |
| | $ | 3.29 |
| | $ | 3.31 |
| | $ | 3.79 |
|
| Transportation costs (per BOE) | $ | 6.39 |
| | $ | 6.24 |
| | $ | 5.95 |
| | $ | 6.06 |
|
| Production taxes as a percent of oil, gas, and NGL production revenue | 4.3 | % | | 4.5 | % | | 4.6 | % | | 4.2 | % |
| Ad valorem tax expense (per BOE) | $ | 0.17 |
| | $ | 0.21 |
| | $ | 0.19 |
| | $ | 0.27 |
|
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) | $ | 12.81 |
| | $ | 13.70 |
| | $ | 14.75 |
| | $ | 15.96 |
|
| General and administrative (per BOE) | $ | 2.49 |
| | $ | 2.31 |
| | $ | 1.97 |
| | $ | 2.40 |
|
Note: Amounts may not calculate due to rounding. |
| | | | | | | | | | | | | | | |
| | For the Three Months Ended |
| | December 31, | | September 30, | | June 30, | | March 31, |
| | 2019 | | 2019 | | 2019 | | 2019 |
| Average net daily production equivalent (MBOE per day) | 138.8 |
| | 134.9 |
| | 136.5 |
| | 118.7 |
|
| Lease operating expense (per BOE) | $ | 4.67 |
| | $ | 4.73 |
| | $ | 4.16 |
| | $ | 5.20 |
|
| Transportation costs (per BOE) | $ | 3.46 |
| | $ | 4.00 |
| | $ | 4.00 |
| | $ | 4.08 |
|
| Production taxes as a percent of oil, gas, and NGL production revenue | 4.2 | % | | 4.1 | % | | 4.0 | % | | 4.1 | % |
| Ad valorem tax expense (per BOE) | $ | 0.37 |
| | $ | 0.39 |
| | $ | 0.44 |
| | $ | 0.76 |
|
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) | $ | 17.91 |
| | $ | 17.02 |
| | $ | 16.61 |
| | $ | 16.63 |
|
| General and administrative (per BOE) | $ | 2.92 |
| | $ | 2.63 |
| | $ | 2.49 |
| | $ | 3.00 |
|
A Year-to-Year Overview of Selected Production and Financial Information, Including Trends:Trends
| | | | | For the Years Ended December 31, | | Amount Change Between | | Percent Change Between | | For the Years Ended December 31, | | Amount Change Between | | Percent Change Between |
| | | 2016 | | 2015 | | 2014 | | 2016/2015 | | 2015/2014 | | 2016/2015 | | 2015/2014 | | 2019 | | 2018 | | 2017 | | 2019/2018 | | 2018/2017 | | 2019/2018 | | 2018/2017 |
Net production volumes (1) | | | | | | | | | | | | | | |
Net production volumes: (1) | | Net production volumes: (1) | | | | | | | | | | | | | |
| Oil (MMBbl) | Oil (MMBbl) | 16.6 |
| | 19.2 |
| | 16.7 |
| | (2.6 | ) | | 2.6 |
| | (14 | )% | | 15 | % | Oil (MMBbl) | 21.9 |
| | 18.8 |
| | 13.7 |
| | 3.1 |
| | 5.1 |
| | 17 | % | | 37 | % |
| Gas (Bcf) | Gas (Bcf) | 146.9 |
| | 173.6 |
| | 152.9 |
| | (26.7 | ) | | 20.7 |
| | (15 | )% | | 14 | % | Gas (Bcf) | 109.8 |
| | 103.2 |
| | 123.0 |
| | 6.6 |
| | (19.8 | ) | | 6 | % | | (16 | )% |
| NGLs (MMBbl) | NGLs (MMBbl) | 14.2 |
| | 16.1 |
| | 13.0 |
| | (1.9 | ) | | 3.1 |
| | (12 | )% | | 24 | % | NGLs (MMBbl) | 8.1 |
| | 7.9 |
| | 10.3 |
| | 0.2 |
| | (2.4 | ) | | 2 | % | | (23 | )% |
| Equivalent (MMBOE) | Equivalent (MMBOE) | 55.3 |
| | 64.2 |
| | 55.1 |
| | (8.9 | ) | | 9.1 |
| | (14 | )% | | 16 | % | Equivalent (MMBOE) | 48.3 |
| | 43.9 |
| | 44.5 |
| | 4.4 |
| | (0.6 | ) | | 10 | % | | (1 | )% |
Average net daily production (1) | | | | | | | | | | | | | | |
Average net daily production: (1) | | Average net daily production: (1) | | | | | | | | | | | | | |
| Oil (MBbl per day) | Oil (MBbl per day) | 45.4 |
| | 52.7 |
| | 45.6 |
| | (7.3 | ) | | 7.0 |
| | (14 | )% | | 15 | % | Oil (MBbl per day) | 59.9 |
| | 51.4 |
| | 37.4 |
| | 8.5 |
| | 14.0 |
| | 17 | % | | 37 | % |
| Gas (MMcf per day) | Gas (MMcf per day) | 401.5 |
| | 475.7 |
| | 419.0 |
| | (74.2 | ) | | 56.7 |
| | (16 | )% | | 14 | % | Gas (MMcf per day) | 300.8 |
| | 282.7 |
| | 337.0 |
| | 18.1 |
| | (54.3 | ) | | 6 | % | | (16 | )% |
| NGLs (MBbl per day) | NGLs (MBbl per day) | 38.8 |
| | 44.0 |
| | 35.6 |
| | (5.2 | ) | | 8.4 |
| | (12 | )% | | 24 | % | NGLs (MBbl per day) | 22.2 |
| | 21.8 |
| | 28.2 |
| | 0.5 |
| | (6.4 | ) | | 2 | % | | (23 | )% |
| Equivalent (MBOE per day) | Equivalent (MBOE per day) | 151.0 |
| | 175.9 |
| | 151.1 |
| | (24.9 | ) | | 24.9 |
| | (14 | )% | | 16 | % | Equivalent (MBOE per day) | 132.3 |
| | 120.3 |
| | 121.8 |
| | 12.0 |
| | (1.5 | ) | | 10 | % | | (1 | )% |
| Oil, gas, and NGL production revenue (in millions) | | | | | | | | | | | |
Oil, gas, and NGL production revenue (in millions): (1) | | Oil, gas, and NGL production revenue (in millions): (1) | | | | | | | | | | | | |
| Oil production revenue | Oil production revenue | $ | 611.8 |
| | $ | 797.3 |
| | $ | 1,348.3 |
| | $ | (185.5 | ) | | $ | (551.0 | ) | | (23 | )% | | (41 | )% | Oil production revenue | $ | 1,183.2 |
| | $ | 1,065.7 |
| | $ | 654.3 |
| | $ | 117.5 |
| | $ | 411.4 |
| | 11 | % | | 63 | % |
| Gas production revenue | Gas production revenue | 337.3 |
| | 447.0 |
| | 699.8 |
| | (109.7 | ) | | (252.8 | ) | | (25 | )% | | (36 | )% | Gas production revenue | 262.5 |
| | 354.5 |
| | 369.4 |
| | (91.9 | ) | | (15.0 | ) | | (26 | )% | | (4 | )% |
| NGL production revenue | NGL production revenue | 229.3 |
| | 255.6 |
| | 433.4 |
| | (26.3 | ) | | (177.8 | ) | | (10 | )% | | (41 | )% | NGL production revenue | 140.0 |
| | 216.2 |
| | 230.1 |
| | (76.2 | ) | | (13.9 | ) | | (35 | )% | | (6 | )% |
| Total | $ | 1,178.4 |
| | $ | 1,499.9 |
| | $ | 2,481.5 |
| | $ | (321.5 | ) | | $ | (981.6 | ) | | (21 | )% | | (40 | )% | |
| Oil, gas, and NGL production expense (in millions) | | | | | | | | | | | |
| Total oil, gas, and NGL production revenue | | Total oil, gas, and NGL production revenue | $ | 1,585.8 |
| | $ | 1,636.4 |
| | $ | 1,253.8 |
| | $ | (50.6 | ) | | $ | 382.6 |
| | (3 | )% | | 31 | % |
Oil, gas, and NGL production expense (in millions): (1) | | Oil, gas, and NGL production expense (in millions): (1) | | | | | | | | | | | | |
| Lease operating expense | Lease operating expense | $ | 194.0 |
| | $ | 239.6 |
| | $ | 235.8 |
| | $ | (45.6 | ) | | $ | 3.8 |
| | (19 | )% | | 2 | % | Lease operating expense | $ | 225.5 |
| | $ | 208.1 |
| | $ | 196.9 |
| | $ | 17.4 |
| | $ | 11.2 |
| | 8 | % | | 6 | % |
| Transportation costs | Transportation costs | 340.3 |
| | 386.6 |
| | 337.1 |
| | (46.3 | ) | | 49.5 |
| | (12 | )% | | 15 | % | Transportation costs | 187.1 |
| | 191.5 |
| | 243.6 |
| | (4.4 | ) | | (52.1 | ) | | (2 | )% | | (21 | )% |
| Production taxes | Production taxes | 51.9 |
| | 72.4 |
| | 117.2 |
| | (20.5 | ) | | (44.8 | ) | | (28 | )% | | (38 | )% | Production taxes | 65.0 |
| | 66.9 |
| | 52.4 |
| | (1.9 | ) | | 14.5 |
| | (3 | )% | | 28 | % |
| Ad valorem tax expense | Ad valorem tax expense | 11.4 |
| | 25.0 |
| | 25.8 |
| | (13.6 | ) | | (0.8 | ) | | (54 | )% | | (3 | )% | Ad valorem tax expense | 23.1 |
| | 20.9 |
| | 15.0 |
| | 2.2 |
| | 5.9 |
| | 10 | % | | 39 | % |
| Total | $ | 597.6 |
| | $ | 723.6 |
| | $ | 715.9 |
| | $ | (126.0 | ) | | $ | 7.7 |
| | (17 | )% | | 1 | % | |
Realized price, before the effect of derivative settlements | | | | | | | | | | | |
| Total oil, gas, and NGL production expense | | Total oil, gas, and NGL production expense | $ | 500.7 |
| | $ | 487.4 |
| | $ | 507.9 |
| | $ | 13.3 |
| | $ | (20.5 | ) | | 3 | % | | (4 | )% |
| Realized price, before the effect of derivative settlements: | | Realized price, before the effect of derivative settlements: | | | | | | | | | | |
| Oil (per Bbl) | Oil (per Bbl) | $ | 36.85 |
| | $ | 41.49 |
| | $ | 80.97 |
| | $ | (4.64 | ) | | $ | (39.48 | ) | | (11 | )% | | (49 | )% | Oil (per Bbl) | $ | 54.10 |
| | $ | 56.80 |
| | $ | 47.88 |
| | $ | (2.70 | ) | | $ | 8.92 |
| | (5 | )% | | 19 | % |
| Gas (per Mcf) | Gas (per Mcf) | $ | 2.30 |
| | $ | 2.57 |
| | $ | 4.58 |
| | $ | (0.27 | ) | | $ | (2.01 | ) | | (11 | )% | | (44 | )% | Gas (per Mcf) | $ | 2.39 |
| | $ | 3.43 |
| | $ | 3.00 |
| | $ | (1.04 | ) | | $ | 0.43 |
| | (30 | )% | | 14 | % |
| NGLs (per Bbl) | NGLs (per Bbl) | $ | 16.16 |
| | $ | 15.92 |
| | $ | 33.34 |
| | $ | 0.24 |
| | $ | (17.42 | ) | | 2 | % | | (52 | )% | NGLs (per Bbl) | $ | 17.26 |
| | $ | 27.22 |
| | $ | 22.35 |
| | $ | (9.96 | ) | | $ | 4.87 |
| | (37 | )% | | 22 | % |
| Per BOE | Per BOE | $ | 21.32 |
| | $ | 23.36 |
| | $ | 45.01 |
| | $ | (2.04 | ) | | $ | (21.65 | ) | | (9 | )% | | (48 | )% | Per BOE | $ | 32.84 |
| | $ | 37.27 |
| | $ | 28.20 |
| | $ | (4.43 | ) | | $ | 9.07 |
| | (12 | )% | | 32 | % |
Per BOE data (1) | | | | | | | | | | | | | | |
| Per BOE data: | | Per BOE data: | | | | | | | | | | | | | |
| Production costs: | Production costs: | | | | | | | | | | | | | | Production costs: | | | | | | | | | | | | | |
| Lease operating expense | Lease operating expense | $ | 3.51 |
| | $ | 3.73 |
| | $ | 4.28 |
| | $ | (0.22 | ) | | $ | (0.55 | ) | | (6 | )% | | (13 | )% | Lease operating expense | $ | 4.67 |
| | $ | 4.74 |
| | $ | 4.43 |
| | $ | (0.07 | ) | | $ | 0.31 |
| | (1 | )% | | 7 | % |
| Transportation costs | Transportation costs | $ | 6.16 |
| | $ | 6.02 |
| | $ | 6.11 |
| | $ | 0.14 |
| | $ | (0.09 | ) | | 2 | % | | (1 | )% | Transportation costs | $ | 3.88 |
| | $ | 4.36 |
| | $ | 5.48 |
| | $ | (0.48 | ) | | $ | (1.12 | ) | | (11 | )% | | (20 | )% |
| Production taxes | Production taxes | $ | 0.94 |
| | $ | 1.13 |
| | $ | 2.13 |
| | $ | (0.19 | ) | | $ | (1.00 | ) | | (17 | )% | | (47 | )% | Production taxes | $ | 1.35 |
| | $ | 1.52 |
| | $ | 1.18 |
| | $ | (0.17 | ) | | $ | 0.34 |
| | (11 | )% | | 29 | % |
| Ad valorem tax expense | Ad valorem tax expense | $ | 0.21 |
| | $ | 0.39 |
| | $ | 0.46 |
| | $ | (0.18 | ) | | $ | (0.07 | ) | | (46 | )% | | (15 | )% | Ad valorem tax expense | $ | 0.48 |
| | $ | 0.48 |
| | $ | 0.34 |
| | $ | — |
| | $ | 0.14 |
| | — | % | | 41 | % |
Total production costs (1) | | Total production costs (1) | $ | 10.38 |
| | $ | 11.10 |
| | $ | 11.43 |
| | $ | (0.72 | ) | | $ | (0.33 | ) | | (6 | )% | | (3 | )% |
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | | Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 17.06 |
| | $ | 15.15 |
| | $ | 12.53 |
| | $ | 1.91 |
| | $ | 2.62 |
| | 13 | % | | 21 | % |
| General and administrative | General and administrative | $ | 2.29 |
| | $ | 2.46 |
| | $ | 3.03 |
| | $ | (0.17 | ) | | $ | (0.57 | ) | | (7 | )% | | (19 | )% | General and administrative | $ | 2.75 |
| | $ | 2.65 |
| | $ | 2.64 |
| | $ | 0.10 |
| | $ | 0.01 |
| | 4 | % | | — | % |
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 14.30 |
| | $ | 14.34 |
| | $ | 13.92 |
| | $ | (0.04 | ) | | $ | 0.42 |
| | — | % | | 3 | % | |
Derivative settlement gain (2) | $ | 5.96 |
| | $ | 7.98 |
| | $ | 0.22 |
| | $ | (2.02 | ) | | $ | 7.76 |
| | (25 | )% | | 3,527 | % | |
| Earnings per share information | | | | | | | | | | | | | | |
Derivative settlement gain (loss) (2) | | Derivative settlement gain (loss) (2) | $ | 0.81 |
| | $ | (3.09 | ) | | $ | 0.48 |
| | $ | 3.90 |
| | $ | (3.57 | ) | | 126 | % | | (744 | )% |
| Earnings per share information: | | Earnings per share information: | | | | | | | | | | | | | |
| Basic weighted-average common shares outstanding (in thousands) | | Basic weighted-average common shares outstanding (in thousands) | 112,544 |
| | 111,912 |
| | 111,428 |
| | 632 |
| | 484 |
| | 1 | % | | — | % |
| Diluted weighted-average common shares outstanding (in thousands) | | Diluted weighted-average common shares outstanding (in thousands) | 112,544 |
| | 113,502 |
| | 111,428 |
| | (958 | ) | | 2,074 |
| | (1 | )% | | 2 | % |
| Basic net income (loss) per common share | Basic net income (loss) per common share | $ | (9.90 | ) | | $ | (6.61 | ) | | $ | 9.91 |
| | $ | (3.29 | ) | | $ | (16.52 | ) | | 50 | % | | (167 | )% | Basic net income (loss) per common share | $ | (1.66 | ) | | $ | 4.54 |
| | $ | (1.44 | ) | | $ | (6.20 | ) | | $ | 5.98 |
| | (137 | )% | | 415 | % |
| Diluted net income (loss) per common share | Diluted net income (loss) per common share | $ | (9.90 | ) | | $ | (6.61 | ) | | $ | 9.79 |
| | $ | (3.29 | ) | | $ | (16.40 | ) | | 50 | % | | (168 | )% | Diluted net income (loss) per common share | $ | (1.66 | ) | | $ | 4.48 |
| | $ | (1.44 | ) | | $ | (6.14 | ) | | $ | 5.92 |
| | (137 | )% | | 411 | % |
| Basic weighted-average common shares outstanding (in thousands) | 76,568 |
| | 67,723 |
| | 67,230 |
| | 8,845 |
| | 493 |
| | 13 | % | | 1 | % | |
| Diluted weighted-average common shares outstanding (in thousands) | 76,568 |
| | 67,723 |
| | 68,044 |
| | 8,845 |
| | (321 | ) | | 13 | % | | — | % | |
| |
(1) | Amounts and percentage changes may not calculate due to rounding. |
| |
(2) | Natural gas derivativeDerivative settlements for the years ended December 31, 2015,2019, 2018, and 2014, include $15.3 million and $5.6 million, respectively,2017, are included within the net derivative (gain) loss line item in the accompanying consolidated statements of early settlementsoperations (“accompanying statements of futures contracts as a result of divesting assets in our Mid-Continent region. These early settlements increased the effect of derivative settlements by $0.24 and $0.10 per BOE for the years ended December 31, 2015, and 2014, respectively.operations”). |
Average net equivalent daily production for the year ended December 31, 2019, increased 10 percent compared with 2018. This increase was primarily driven by a 25 percent increase in production volumes from our Midland Basin assets for the year ended December 31, 2019, compared with 2018. Production volumes from our South Texas assets for the year ended December 31, 2019, were relatively flat compared with 2018. We divested our remaining producing assets in the Rocky Mountain region in the first half of 2018. We expect total production volumes in 2020 to decline slightly compared with 2019; however, we expect total oil volumes to increase. As a result, we expect oil volumes to be approximately 50 percent of our total production mix in 2020. Please refer toComparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion.
We present certain information on a per BOE information because we use this informationbasis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis. Average net daily productionanalysis and discussion.
Our realized price before the effect of derivative settlements on a per BOE basis decreased 12 percent for the year ended December 31, 2016, decreased 14 percent2019, compared with the same period in 2015,2018. This decrease was primarily driven by our reduced drillinglower benchmark commodity prices for oil, gas, and completion activity andNGLs, as well as increased regional differentials in the divestitureMidland Basin for natural gas caused by tight takeaway capacity. In the first half of assets. Overall,2019, certain third-party midstream force majeure events negatively affected the price we expect 2017 total net production to decrease compared with 2016 due to the impact of closed and anticipated divestitures, which will be partially offset by the increase in development activity inreceived for our Midland Basin program. Our average net daily productiongas production. Regional differentials for assets sold and assetsgas in the Midland Basin are expected to be sold by mid-2017, specificallycontinue to negatively affect our outside-operated Eagle Ford shale and Divide County assets, was approximately 52.6 MBOE per day during 2016. Please referrealized prices in 2020. Additional expected take-away capacity is anticipated toComparison of Financial Results and Trends Between 2016 and 2015 and Between 2015 and 2014 below for additional discussion.
Changes come online in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our realized price on a per BOE basis forearly 2021. For the year ended December 31, 2016, decreased nine percent compared with 2015 as2019, we recognized a resultgain of declines in commodity prices in$0.81 per BOE on the first halfsettlement of 2016. Ourour derivative contracts, resulted incompared to a $5.96 settlement gain on arecognized loss of $3.09 per BOE basis for the year ended December 31, 2016, which decreased 25 percent compared with 2015 settlements.in 2018.
Lease operating expense (“LOE”) on a per BOE basis was relatively flat for the year ended December 31, 2016, decreased six percent2019, compared with 2018, despite the same periodincrease in 2015 due to lower service provider costs and reduced workover activity. We experience volatility in our LOEoil production as a resultpercentage of the impact industry activity has on service provider costs and seasonalityour total production. The increase in workover expense. Throughout 2015 and into 2016, industry activity decreased in light of the low commodity price environment resulting in service providers lowering costs. For 2017, weabsolute LOE was primarily driven by increased production. We expect LOE on a per BOE basis to be relatively flathigher in 2020 compared with 2016.2019 as our product mix continues to shift towards more oil production. We expect that any increaseanticipate volatility in LOE on a per BOE basis as a result of changes in total production, our overall production mix, timing of workover projects, and industry activity, all of which impacts service provider costs resulting from increased development activity in the Midland Basin will be offset by the executed and planned divestitures of our higher cost Williston Basin properties.costs.
Transportation costs on a per BOE basis decreased 11 percent for the year ended December 31, 2016, remained relatively flat2019, compared with 2018. The decrease was driven primarily by an increase in the same period in 2015.percentage of production generated from our Midland Basin assets, as production from these assets is typically sold at or near the wellhead and incurs minimal transportation costs. We expect total transportation costs onto fluctuate relative to changes in production from our South Texas assets, which incur the majority of our transportation costs. On a per BOE basis, we expect transportation costs to decrease in 2017 upon selling our outside-operated Eagle Ford shale assets in the early part of the year and2020, compared with 2019, as production from our Midland Basin assets becomingcontinues to become a larger portion of our production mix. The majority of our Midland Basin production is sold at the wellhead under current contracts, and therefore, there is minimal transportation expense separately recorded on the accompanying statements of operations.total production.
Production taxes on a per BOE basis for the year ended December 31, 2016,2019, decreased 1711 percent compared with the same period in 2015 driven by the decrease in production revenues, as well as2018, primarily due to a 12 percent decrease in our company-wide production tax rate.realized price on a per BOE basis before the effect of derivative settlements for the year ended December 31, 2019, compared with 2018. Our overall production tax rate for each of the years ended December 31, 2016,2019, and 2015,2018 was 4.4 percent and 4.8 percent, respectively.4.1 percent. We expect our overall production tax rate to remain consistent in 2020, compared with 2019. We generally expect production tax expense to trend with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can allalso impact the amount of production tax we recognize. For 2017, we generally expect our production tax rate to decrease year-over-year as a result of our closed and anticipated divestitures; however, we expect an increase in production taxes on a per BOE basis in line with improved commodity prices.
Ad valorem tax expense on a per BOE basis for the year ended December 31, 2016, decreased 46 percent2019, was flat compared with 2018, as the same periodincreases on an absolute basis, resulting from changes in 2015 due to the lower valuation of properties subject to ad valorem taxesour asset and production base, were consistent with higher production volumes. We anticipate volatility in 2016 as a result of declining commodity prices. We expect ad valorem tax expense on a per BOE and absolute basis to increase in 2017 as a result of continuing changes in our asset and production base year-over-year. The majoritythe valuation of our ad valorem tax expense is related to our Texasproducing properties. Since we have acquired producing properties in Texas and divested properties in our Rocky Mountain region, we expect ad valorem tax expense on an absolute and per BOE basis to increase in 2017. Additionally, we expect an increase in commodity price assumptions used in 2017 property tax valuations.
General and administrative (“G&A”) expense decreased seven percent on a per BOE basis for the year ended December 31, 2016, compared with the same period in 2015 as our absolute G&A expense decreased at a faster rate than the decrease in production volumes. The 20 percent decrease in absolute G&A expense is due largely to lower
headcount in 2016. We closed our Tulsa, Oklahoma regional office upon selling our Mid-Continent assets in the second quarter of 2015, conducted a company-wide workforce reduction in the third quarter of 2016, and closed our Billings, Montana regional office in the fourth quarter of 2016. These events resulted in a reduction in headcount; however, we incurred $5.1 million and $9.3 million in related exit and disposal costs for the years ended December 31, 2016, and 2015, respectively. We expect G&A expense on an absolute basis to remain relatively flat in 2017 compared with 2016 due to reduced headcount in 2016 being offset by headcount changes resulting from recent and anticipated acquisition and divestiture activity and an expected increase in base and short-term incentive compensation. However, we expect an overall increase in G&A expense on a per BOE basis in 2017 due to a decrease in production volumes.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense remained flaton a per BOE basis increased 13 percent for the year ended December 31, 2019, compared with 2018. The increase was driven by our focus on developing oil producing assets in the Midland Basin, which have higher depletion rates than our primarily gas and NGL producing assets in South Texas. Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes. In general, we expect DD&A expense on a per BOE basis in 2020 to increase compared with 2019 as production from our Midland Basin assets continues to become a larger portion of our total production.
General and administrative (“G&A”) expense on a per BOE basis for the year ended December 31, 2016,2019, increased four percent compared with 2018. The increase was primarily due to a reduction in the amount of employee compensation that was reclassified to exploration expense as compared with the same periodprior year, as more employee time was allocated to development activities in 2015. Our DD2019. During the fourth quarter of 2019, we announced the reorganization of certain functions to eliminate duplicative regional operational functions and reduce overhead costs, which we expect will result in reduced G&A rate fluctuates asexpense in future years. As a result, of impairments, planned and closed divestitures, and changeswe expect to incur total charges related to this reorganization ranging from $8.0 million to $8.5 million, including $4.2 million incurred in the mixfourth quarter of our production and the underlying proved reserve volumes. In the beginning of 2016, our DD2019. We expect G&A rate was higher as a result of theexpense to decrease in our proved reserve volumes at December 31, 2015. This increase was offset by the impact of assets held for sale throughout the year, as these assets were not depleted while classified as held for sale. In general, we expect DD&A expensetotal and on a per BOE basis to decrease in 2017 due to selling our higher cost Raven/Bear Den assets in late 2016 and our Divide County assets being classified as held for sale in the first quarter of 20172020 compared with no recorded DD&A expense until the sale is finalized (assuming a definitive agreement is executed and all customary closing conditions are met). 2019.
Please refer to Comparison of Financial Results and Trends Between 2016 and 2015 and Between 2015 and 2014 for additional discussion.
Please refer to the section Note 9 - Earnings perPer Share in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional discussion on the types of shares included in our basic and diluted net income (loss) per common share calculations. Our basic and diluted weighted-average share count has increased in 2016 compared with 2015 due to the public and private equity offerings of our common stock made in the last half of 2016. We recorded a net loss for each of the years ended
December 31, 2016,2019, and 2015.2017. Consequently, our unvested RSUsall potentially dilutive shares were anti-dilutive and contingent PSUs were anti-dilutiveexcluded from the calculation of diluted net loss per common share for the years ended December 31, 2016,2019, and 2015.
2017. For the year ended December 31, 2018, we recorded net income and thus considered dilutive shares in the calculation of diluted net income per common share as of December 31, 2018.
Comparison of Financial Results and Trends Between 20162019 and 20152018 and Between 20152018 and 20142017
Oil, Gas,Please refer to Comparison of Financial Results and NGLTrends Between 2018 and 2017 and Between 2017 and 2016 in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2018 Annual Report on Form 10-K, filed with the SEC on February 21, 2019, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2018, compared with the year ended December 31, 2017.
Net equivalent production, production revenue, and production expense
The following table presents the regional changes in our oil, gas, and NGLnet equivalent production, production revenues,revenue, and production costsexpense between the years ended December 31, 2016,2019, and 2015:2018:
|
| | | | | | | | | | |
| | Average Net Daily Production Increase (Decrease) | | Production Revenue Increase (Decrease) | | Production Costs Decrease |
| | (MBOE/d) | | (in millions) | | (in millions) |
| South Texas & Gulf Coast | (20.3 | ) | | $ | (240.8 | ) | | $ | (93.6 | ) |
| Rocky Mountain | (2.9 | ) | | (90.7 | ) | | (19.6 | ) |
| Permian | 2.9 |
| | 35.9 |
| | (0.6 | ) |
Mid-Continent (1) | (4.6 | ) | | (25.9 | ) | | (12.2 | ) |
| Total | (24.9 | ) | | $ | (321.5 | ) | | $ | (126.0 | ) |
|
| | | | | | | | | | |
| | Net Equivalent Production Increase (Decrease) | | Production Revenue Increase (Decrease) | | Production Expense Increase (Decrease) |
| | (MBOE per day) | | (in millions) | | (in millions) |
| Midland Basin | 14.6 |
| | $ | 131.1 |
| | $ | 31.5 |
|
| South Texas | 0.4 |
| | (124.5 | ) | | 5.2 |
|
Rocky Mountain (1) | (3.1 | ) | | (57.2 | ) | | (23.3 | ) |
| Total | 12.0 |
| | $ | (50.6 | ) | | $ | 13.3 |
|
Note: Amounts may not calculate due to rounding.
| |
(1) | We divested our Mid-Continentall remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2015.2018. |
We experienced a 1410 percent decreaseincrease in net equivalent production volumes in 20162019 compared with 2018, primarily as a result of increased production from 2015our Midland Basin assets. As a result of increased Midland Basin production, oil production as a percentage of our overall product mix increased from 43 percent in 2018, to 45 percent in 2019. Oil, gas, and NGL production revenues decreased three percent for the year ended December 31, 2019, compared with 2018, as a result of lower commodity pricing and the divestiture in the first half of 2018 of our remaining producing assets in the Rocky Mountain region. Total production expense for the year ended December 31, 2019, increased three percent compared with 2018, due to a reduction in our drillingincreased LOE and completion activityad valorem tax expense, partially offset by decreased production taxes and assets divested in both years. Additionally, our realized pricetransportation costs. Production expense on a per BOE basis decreased ninesix percent in 2016for the year ended December 31, 2019, compared with 2018, primarily due to increased production volumes, decreased transportation costs, and decreased production taxes resulting from 2015. Both of these factors resulted in a 21 percent decrease inlower oil, gas, and NGL production revenue between the two periods. Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends above for discussion of the expected downward trend in production in 2017 due to assets sold in 2016 and expected to be sold in 2017. Please refer to the caption Oil, gas, and NGL production expense below for discussion of the reasons for the decrease in total production costs in 2016 compared with 2015.
revenues.
The following table presents the regional changes in our oil, gas, and NGLnet equivalent production, production revenues,revenue, and production costsexpense between the years ended December 31, 2015,2018 and 2014:2017:
|
| | | | | | | | | | |
| | Average Net Daily Production Increase (Decrease) | | Production Revenue Decrease | | Production Costs Increase (Decrease) |
| | (MBOE/d) | | (in millions) | | (in millions) |
| South Texas & Gulf Coast | 22.8 |
| | $ | (587.8 | ) | | $ | 54.0 |
|
| Rocky Mountain | 7.2 |
| | (230.5 | ) | | (8.2 | ) |
| Permian | (0.2 | ) | | (98.8 | ) | | (16.6 | ) |
Mid-Continent (1) | (4.9 | ) | | (64.5 | ) | | (21.5 | ) |
| Total | 24.9 |
| | $ | (981.6 | ) | | $ | 7.7 |
|
|
| | | | | | | | | | |
| | Net Equivalent Production Increase (Decrease) | | Production Revenue Increase (Decrease) | | Production Expense Increase (Decrease) |
| | (MBOE per day) | | (in millions) | | (in millions) |
| Midland Basin | 27.4 |
| | $ | 582.5 |
| | $ | 89.5 |
|
| South Texas | (20.8 | ) | | (95.9 | ) | | (64.5 | ) |
Rocky Mountain (1) | (8.1 | ) | | (104.0 | ) | | (45.5 | ) |
| Total | (1.5 | ) | | $ | 382.6 |
| | $ | (20.5 | ) |
Note: Amounts may not calculate due to rounding.
| |
(1) | We divested our Mid-Continentall remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2015.2018. |
We experienced a 16one percent decrease in net equivalent production in 2018 compared with 2017. The decrease in overall production volumes was a result of decreased production from our operated Eagle Ford shale assets as a result of reduced capital investment, the divestiture of our outside-operated Eagle Ford shale assets which occurred in the first quarter of 2017, and the divestiture of our remaining producing assets in the Rocky Mountain region in the first half of 2018. Production decreases in the South Texas and Rocky Mountain regions were predominately offset by the 91 percent production volume increase in our Midland Basin assets for the year ended December 31, 2018, compared with 2017. Increased production in the Midland Basin also drove oil
production as a percentage of our overall product mix to increase from 31 percent in 2017, to 43 percent in 2018. The increase in higher margin oil production also increased realized prices, before the effects of derivative settlements, on a per BOE basis by 32 percent in 2018, resulting in a 31 percent increase in equivalent production volumes in 2015 from 2014 despite selling our Mid-Continent assets in the second quarter of 2015. This increase was primarily driven by continued development in our Eagle Ford shale and Bakken/Three Forks programs. However, oil, gas, and NGL production revenue betweenfor the two periodsyear ended 2018 compared with 2017. Production expense in 2018, compared with 2017, decreased 40four percent, due to a 48 percent decreaseand was primarily driven by the divestiture of the remaining assets in realized price on a per BOE basis. our Rocky Mountain region in the first half of 2018, which had the highest average production costs in our portfolio.
Please refer to the caption Oil, gas, and NGL production expense below for discussion on the reasons for the change in production costs in 2015 from 2014.
Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends above for realized prices received before the effects of derivative settlements for the years ended December 31, 2016, 2015, and 2014, and discussion of trends on a per BOE basis.basis for the years ended December 31, 2019, 2018, and 2017.
Net gain (loss) on divestiture activity
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Net gain on divestiture activity | $ | 37.1 |
| | $ | 43.0 |
| | $ | 0.6 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Net gain (loss) on divestiture activity | $ | 0.9 |
| | $ | 426.9 |
| | $ | (131.0 | ) |
No material divestitures occurred during 2019. The $426.9 million net gain on divestiture activity recorded for the year ended December 31, 2016, is primarily a2018, was the result of the approximate $29.5 million net gain recorded on our Raven/Bear Den assets sold in the fourth quarter of 2016, as well as a $6.3 million total net gain of $410.6 million recorded onfor the non-core Williston Basin,divestiture of our Powder River Basin and southeast New Mexico asset divestitures in the third quarter of 2016. Certain of these sold assets were written down(the “PRB Divestiture”), which closed in the first quarter of 20162018, and subsequently written upa combined total net gain of $15.4 million recorded for the completed divestitures of our remaining assets in the Williston Basin located in Divide County, North Dakota (the “Divide County Divestiture”) and our Halff East assets in the Midland Basin (the “Halff East Divestiture”), which closed in the second quarter of 2016 based on changes in the estimated fair value less costs to sell. Subsequent to December 31, 2016, we announced our plan to sell our remaining Williston Basin assets in Divide County, North Dakota. Please refer to Critical Accounting Policies and Estimates below for additional discussion regarding the expected write-down to be recorded in the first quarter of 2017 upon these assets being classified as held for sale.2018.
The net gainloss on divestiture activity recorded for the year ended December 31, 2015, is due to2017, was primarily the $108.4result of $526.5 million of write-downs recorded on certain retained North Dakota assets. These assets were divested in the second quarter of 2018, as discussed above. Partially offsetting these write-downs recorded during 2017, was a $396.8 million total net gain recorded on the sale of our Mid-Continent assets in the second quarter, partially offset by losses on certain other non-core assets sold during 2015.outside-operated Eagle Ford shale assets.
The minimal net gain on divestiture activity recorded for the year ended December 31, 2014, is due to the $26.9 million gain recorded on the sale of non-core Williston Basin properties during the second quarter of 2014, which was mostly offset by write-downs to fair value recorded on other unrelated assets held for sale.
Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additional discussion.
Marketed gas system revenue and expense
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Marketed gas system revenue | $ | — |
| | $ | 9.5 |
| | $ | 24.9 |
|
| Marketed gas system expense | $ | — |
| | $ | 13.9 |
| | $ | 24.5 |
|
There was no marketed gas system revenue or expense in 2016, and there was a decrease in marketed gas system revenue and expense in 2015 from 2014, due to the sale of our Mid-Continent gas assets in the second quarter of 2015, which eliminated all marketing activities for gas produced by third parties.
Other operating revenues
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Other operating revenues | $ | 2.0 |
| | $ | 4.5 |
| | $ | 15.2 |
|
There were no material other operating revenues recorded for the years ended December 31, 2016, or 2015.
Other operating revenues for the year ended December 31, 2014, included a $10.7 million gain related to our settlement with Endeavour Operating Corporation (“Endeavour”), in which we, our working interest partners, and Endeavour agreed to mutually release all claims and dismiss certain litigation in exchange for certain cash payments and other consideration from Endeavour.
Oil, gas, and NGL production expense
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Oil, gas, and NGL production expense | $ | 597.6 |
| | $ | 723.6 |
| | $ | 715.9 |
|
Total production costs for the year ended December 31, 2016, decreased $126.0 million, or 17 percent, from the same period in 2015, primarily due to a 14 percent decrease in net equivalent production volumes, continued declines in service provider costs, and a decrease in production taxes due to lower commodity prices. Please refer to the caption A Year-to-Year Overview of Selected Production and Financial Information, Including Trendsabove for discussion of production costs on a per BOE basis.
Total production costs for the year ended December 31, 2015, slightly increased compared with the same period in 2014 due to a 16 percent increase in net equivalent production volumes and a 15 percent increase in transportation expense resulting from the continued development of our Eagle Ford shale program, largely offset by lower service provider costs and a decrease in production taxes due to lower commodity prices.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 790.7 |
| | $ | 921.0 |
| | $ | 767.5 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 823.8 |
| | $ | 665.3 |
| | $ | 557.0 |
|
DD&A expense for the year ended December 31, 2016, decreased 142019, increased 24 percent compared with 2018. DD&A expense for the same period in 2015 dueyear ended December 31, 2018, increased 19 percent compared with 2017. These increases are directly related to a 14the 25 percent decreaseand 91 percent increases for the years ended December 31, 2019, and 2018, respectively, in production volumes and the impact offrom our Midland Basin assets sold or classified as held for sale throughout 2016 since no DD&A expense is recorded after the point thethese assets were classified as held for sale. The impact fromhave higher depletion rates than our assets divested and held for sale was mostly offset by a higher DD&A rate in the beginning year due to a reduction in our proved reserves at December 31, 2015. South Texas.
Please refer to the caption A Year-to-Year Overview of Selected Production and Financial Information, Including Trendsabove for discussion of DD&A expense on a per BOE basis.
DD&AExploration
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Geological and geophysical expenses | $ | 2.9 |
| | $ | 5.6 |
| | $ | 4.0 |
|
| Exploratory dry hole | 4.8 |
| | — |
| | 2.4 |
|
| Overhead and other expenses | 43.8 |
| | 49.6 |
| | 48.3 |
|
| Total | $ | 51.5 |
| | $ | 55.2 |
| | $ | 54.7 |
|
Exploration expense decreased seven percent for the year ended December 31, 2015, increased 20 percent2019, compared with the same period in 2014 due to an increase in production volumes and2018. The decrease was primarily driven by a higher DD&A rate in 2015, partially offset by our Mid-Continent assets held for salereduction in the beginningamount of 2015employee compensation reclassified to exploration expense as more employee time is being allocated to development activities, which is recognized as G&A expense. Exploration expense is impacted by actual geological and sold ingeophysical studies we perform and the second quarterpotential for exploratory dry hole expense.
Impairment of 2015.
Explorationoil and gas properties
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Geological and geophysical expenses | $ | 11.0 |
| | $ | 7.5 |
| | $ | 11.4 |
|
| Exploratory dry hole | — |
| | 36.6 |
| | 44.4 |
|
| Overhead and other expenses | 54.6 |
| | 76.5 |
| | 74.1 |
|
| Total | $ | 65.6 |
| | $ | 120.6 |
| | $ | 129.9 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Impairment of proved properties | $ | — |
| | $ | — |
| | $ | 3.8 |
|
| Abandonment and impairment of unproved properties | 33.8 |
| | 49.9 |
| | 12.3 |
|
| Total | $ | 33.8 |
| | $ | 49.9 |
| | $ | 16.1 |
|
ExplorationThere was no impairment of proved properties expense recognized for the yearyears ended December 31, 2016, decreased 46 percent compared with 2015 primarily due2019, and 2018. Unproved property abandonments and impairments recorded for the years ended December 31, 2019, and 2018 related to exploratory dry holes being expensed in 2015 (described in the next paragraph) with none recorded in 2016,actual and anticipated lease expirations, as well as reduced overhead costs as a result of reduced exploration activity in 2016. These decreases were partially offset by expenses incurred for a seismic study performedactual and anticipated losses on our recently acquired Midland Basin acreage in the fourth quarter of 2016. An exploratory project resulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry hole and impacts the amount of exploration expense we record. In 2017, we expect to focus on testing and delineating our acquired Midland Basin acreage, and as a result, expect increased exploration activity and related expenses compared with 2016.
Exploration expense for the year ended December 31, 2015, decreased seven percent compared with 2014 mainly due to decreasestitle defects, changes in exploratory dry hole expensedevelopment plans, and geological and geophysical costs (“G&G”) expenses in 2015. During 2015, we expensed one exploratory dry hole in our Rocky Mountain region and three lower cost non-Eagle Ford exploratory dry holes in our South Texas & Gulf Coast region, compared to three higher cost exploratory non-Eagle Ford dry holes expensed in our South Texas & Gulf Coast region in 2014. During the first quarter of 2014, we performed a seismic study in our Powder River Basin program, which resulted in higher G&G expenses in 2014 compared with 2015.other inherent acreage risks.
Impairment of proved properties and Abandonment and impairment of unproved properties
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Impairment of proved properties | $ | 354.6 |
| | $ | 468.7 |
| | $ | 84.5 |
|
| Abandonment and impairment of unproved properties | $ | 80.4 |
| | $ | 78.6 |
| | $ | 75.6 |
|
The majority of our proved property impairment expense for the year ended December 31, 2016, was recorded in the first quarter of 2016 in our outside-operated Eagle Ford shale program as a result of continued commodity price declines. In the fourth quarter of 2016, we recorded proved and unproved property impairment expense on our Powder River Basin assets as a result of negative performance reserve revisions at year-end 2016 and lower market prices on recent third-party acreage transactions. Additionally, we allowed certain leases to expire throughout the year ended December 31, 2016. We expect proved property impairments to beoccur more likely to occurfrequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments towill fluctuate with the timing of lease expirations unsuccessful exploration activities,or defects, and changing economics associated with volatiledecreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions or unsuccessful exploration efforts may result in proved and unproved property impairments. Any amountFuture impairments of future impairment isproved and unproved properties are difficult to predict, butpredict; however, based on our updated commodity price assumptions as of February 15, 2017,6, 2020, we do not expect any
material impairments on assets held for use in the first quarter of 2017 due to2020 resulting from commodity price impacts. Please refer to Critical Accounting Policies and Estimates below for additional discussion.
Proved and unproved property impairments recorded in 2015 were due to continued commodity price declines, largely impacting our Powder River Basin program and certain legacy and non-core assets, as well as our decision to reduce capital invested in the development of our east Texas exploration program in light of the sustained, low commodity price environment.
Proved and unproved property impairments recorded in 2014 were due to the significant decline in commodity prices in late 2014 resulting in changes in our drilling plans and the abandonment of certain acreage, as well as recognition of the outcomes of exploration and delineation wells in certain prospects in our South Texas & Gulf Coast and Permian regions.
Impairment of other property and equipment
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Impairment of other property and equipment | $ | — |
| | $ | 49.4 |
| | $ | — |
|
We impaired our gas gathering system assets in our east Texas program during the year ended December 31, 2015, in conjunction with the impairment of the associated proved and unproved properties resulting from our decision not to allocate additional capital to the program in light of sustained low commodity prices. We did not record impairments of other property and equipment for the years ended December 31, 2016, and 2014.
General and administrative
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| General and administrative | $ | 126.4 |
| | $ | 157.7 |
| | $ | 167.1 |
|
Exit and disposal costs (1) | $ | 5.1 |
| | $ | 9.3 |
| | $ | — |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| General and administrative | $ | 132.8 |
| | $ | 116.5 |
| | $ | 117.3 |
|
| |
(1)
| Exit and disposal costs are recorded in general and administrative expense in the accompanying statements of operations. |
G&A expense increased 14 percent for the year ended December 31, 2016, decreased $31.32019, compared with 2018. Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trendsabove for discussion of G&A expense.
Net derivative (gain) loss
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Net derivative (gain) loss | $ | 97.5 |
| | $ | (161.8 | ) | | $ | 26.4 |
|
We recognized a net derivative loss of $97.5 million or 20 percent, from 2015 primarily due to lower headcountfor the year ended December 31, 2019. For contracts that settled during 2019, the fair value was a net asset of $112.2 million at December 31, 2018, and overhead costsnet cash settlements received totaled $39.2 million, resulting in 2016a $73.0 million net loss. Additionally, we recorded a $24.5 million mark-to-market loss on remaining contracts as of December 31, 2019, resulting from an increase in commodity strip prices toward the closureend of our Tulsa, Oklahoma regional office2019.
We recognized a net derivative gain of $161.8 million for the year ended December 31, 2018. For contracts that settled during 2018, the fair value was a net liability of $108.3 million at December 31, 2017, and net cash settlements paid totaled $135.8 million, resulting in a $27.5 million loss. Offsetting this loss was a $189.3 million mark-to-market gain on remaining contracts as of December 31, 2018, resulting from a decrease in commodity strip prices toward the beginningend of 2018.
We recognized a net derivative loss of $26.4 million for the third quarteryear ended December 31, 2017. For contracts that settled during 2017, the fair value was a net liability of 2015, the company-wide workforce reduction that occurred in the third quarter of 2016, and the closure of our Billings, Montana regional office in the fourth quarter of 2016. For the years ended$60.9 million at December 31, 2016, and 2015, $5.1net cash settlements received totaled $21.2 million, and $9.3resulting in an $82.1 million respectively,gain. Offsetting this gain was a $108.5 million mark-to-market loss on remaining contracts as of exit and disposal costs related to these events was includedDecember 31, 2017, resulting from an increase in G&A expense. commodity strip prices.
Please refer to Note 14 - Exit and Disposal Costs 10 – Derivative Financial Instrumentsin Part II, Item 8 of this report for additional discussion. Additionally, refer to the caption A Year-to-Year Overview of Selected Production and Financial Information, Including Trendsabove for discussion of G&A costs on a per BOE basis.
G&A
Interest expense decreased $9.4 million, or six percent, in 2015 from 2014 due to lower short-term incentive compensation and reduced headcount and overhead costs resulting from the closing of our Tulsa office in the beginning of the third quarter of 2015.
Change in Net Profits Plan liability
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Change in Net Profits Plan liability | $ | (7.2 | ) | | $ | (19.5 | ) | | $ | (29.8 | ) |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Interest expense | $ | (159.1 | ) | | $ | (160.9 | ) | | $ | (179.3 | ) |
Interest expense for the year ended December 31, 2019, was relatively flat compared with 2018. We expect interest expense related to our Senior Notes to be relatively flat in 2020 compared with 2019; however, total interest expense can vary based on the timing and amount of any borrowings against our credit facility.
This non-cashThe $18.4 million, or 10 percent, decrease in interest expense (benefit) generally relatesfor the year ended December 31, 2018, compared with 2017, was driven in part by the redemption of our 6.50% Senior Notes due 2021 (“2021 Senior Notes”), which reduced interest expense related to debt in 2018 by $9.4 million compared with 2017. In addition to the changeoverall reduction in debt, interest expense was also reduced as the estimated valueamount of the associated liability between the reporting periods resulting from settlements made or accrued during the period and changesinterest we capitalized increased given our higher level of development activity in assumptions used in valuing the remaining liability. The non-cash benefit for 2016 was primarily due to the divestiture of assets subject to the Net Profits Plan in 2016. 2018 compared with 2017.
Please refer to Note 11 - Fair Value Measurements 5 – Long-Term Debtin Part II, Item 8 of this report and Overview of Liquidity and Capital Resources below for tabular presentationadditional discussion.
Loss on extinguishment of the change in the Net Profits Plan liability.
The non-cash benefit for 2015 and 2014 was a result of a 72 percent and 52 percent respective decrease in the corresponding liability, resulting from the continued decline in commodity prices and cash payments made or accrued under the plan.
Net derivative (gain) lossdebt
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Net derivative (gain) loss | $ | 250.6 |
| | $ | (408.8 | ) | | $ | (583.3 | ) |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Loss on extinguishment of debt | $ | — |
| | $ | (26.7 | ) | | $ | — |
|
We recognized a net derivative loss of $250.6 million forFor the year ended December 31, 2016. For contracts settled during 2016, the fair value was a net asset of $367.7 million at December 31, 2015, and net cash settlements totaled $329.5 million, resulting in a $38.2 million loss. Additionally,2018, we recorded a $212.4$26.7 million mark-to-marketnet loss on remaining contracts asthe early extinguishment of December 31, 2016, resulting fromour 2021 Senior Notes, 6.50% Senior Notes due 2023 (“2023 Senior Notes”), and a portion of our 6.125% Senior Notes due 2022 (“2022 Senior Notes”). The net loss on extinguishment of debt included $20.4 million associated with the increase in commodity strip prices.premiums paid upon redemption and repurchase, and $6.3 million related to the acceleration of unamortized deferred financing costs.
We recognized a net derivative gain of $408.8 million for the year ended December 31, 2015. For contracts settled during 2015, the fair value was a net asset of $402.7 million at December 31, 2014, and net cash settlements totaled $512.6 million, resulting in a $109.9 million gain. Additionally, we recorded a $298.9 million mark-to-market gain on remaining contracts as of December 31, 2015, resulting from the decrease in commodity strip prices.
We recognized a net derivative gain of $583.3 million for the year ended December 31, 2014. For contracts settled during 2014, the fair value was a net liability of $4.8 million at December 31, 2013, and net cash settlements totaled $12.6 million, resulting in a $17.4 million gain. Additionally, we recorded a $565.9 million mark-to-market gain on remaining contracts as of December 31, 2014, resulting from the decrease in commodity strip prices.
Please refer to Note 10 - Derivative Financial Instruments5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Other operating expenses
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Other operating expenses | $ | 18.0 |
| | $ | 30.6 |
| | $ | 4.7 |
|
Other operating expenses for the year ended December 31, 2016, consisted primarily of drilling rig termination and standby fees of $8.7 million, $2.4 million of materials inventory write-downs, and $3.2 million paid to the lessor to terminate our office lease in Billings, Montana. Other operating expenses for the year ended December 31, 2015, consisted primarily of drilling rig termination and standby fees of $13.7 million, $5.3 million of expense related to estimated claims for payment of royalties on certain Federal and Indian leases, and $4.1 million of materials inventory write-downs. There were no individually material other operating expenses in 2014.
Gain (loss) on extinguishment of debt
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Gain (loss) on extinguishment of debt | $ | 15.7 |
| | $ | (16.6 | ) | | $ | — |
|
For the year ended December 31, 2016, we recorded a $15.7 million net gain on the early extinguishment of a portion of our Senior Notes (as defined and discussed in Note 5 - Long-Term Debt in Part II, Item 8 of this report), which includes approximately $16.4 million associated with the discount realized upon repurchase, slightly offset by approximately $700,000 related to the acceleration of unamortized deferred financing costs.
For the year ended December 31, 2015, we recorded a $16.6 million loss on the early extinguishment of our 6.625% Senior Notes due 2019, which included approximately $12.5 million associated with the premium paid for the tender offer and redemption of the notes and approximately $4.1 million for the acceleration of unamortized deferred financing costs.
Interest expense
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Interest expense | $ | (158.7 | ) | | $ | (128.1 | ) | | $ | (98.6 | ) |
The $30.6 million, or 24 percent, increase in interest expense for the year ended December 31, 2016, compared with the same period in 2015, was due to the additional debt issued in 2016, as presented in Note 5 - Long-Term Debt in Part II, Item 8 of this report, as well as $10.0 million paid to terminate a second lien facility that was not necessary to fund the Rock Oil Acquisition.
The $29.5 million, or 30 percent, increase in interest expense for the year ended December 31, 2015, compared with the same period in 2014, was primarily due to a larger outstanding debt balance in 2015, partially offset by a slight reduction in our weighted-average interest rate.
Please refer to Overview of Liquidity and Capital Resources below for additional discussion of weighted-average interest and borrowing rates for the years presented.
Income tax (expense) benefit
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| | (in millions, except tax rate) | (in millions, except tax rate) |
| Income tax (expense) benefit | $ | 444.2 |
| | $ | 275.2 |
| | $ | (398.6 | ) | $ | 44.0 |
| | $ | (143.4 | ) | | $ | 183.0 |
|
| Effective tax rate | 37.0 | % | | 38.1 | % | | 37.4 | % | 19.1 | % | | 22.0 | % | | 53.2 | % |
The decrease in the effective tax rate in 2016for the year ended December 31, 2019, compared with 2015 reflects2018, was primarily due to the differing effects of permanent items on the loss before income taxes for the year ended December 31, 2019, compared to the impact of these items on income before income taxes for 2018. Excess tax deficiencies from stock-based compensation awards, limits on expensing of certain covered individual’s compensation, and other permanent expense items reduced the tax benefit of Oklahoma permanentrate for the year ended December 31, 2019. These same items increased the tax benefits and claimed research and development credits recognized in 2015.expense rate for the year ended December 31, 2018. The effective tax benefit rate realized in 2016 primarily includes a positive effect from the divestiture of properties in high marginal rate states and acquisition of properties in a lower marginal rate state, as well as a positive effect from the release of certain valuation allowances on utilized tax assets. The tax gain recognized on the Raven/Bear Den divestiture, which closedreduction in the fourth quartertax expense rate also reflects a cumulative effect in 2018 from divestitures, and the impact of 2016, is much larger thana correlative change to our state apportionment rate.
The decrease in the estimated and recorded book gain. The same is true for announced property sales scheduled to occur in 2017. As a result, we were able to consider tax planning strategies which would allow for the utilization of net operating loss carryovers in certain states which we previously determined would expire before they could be used, as well as utilization of certain carryover federal tax deductions, limited based upon taxable income, which were also expected to expire. As of this date, we intend to implement these planning strategies to utilize deferred tax assets, but cannot ensure that future events will not change these plans and cause the valuation allowances to be reestablished. In general, our historical effective tax rate has not varied significantlyfor the year ended December 31, 2018, compared with 2017 was primarily due to the impacts of the Tax Cuts and Jobs Act (the “2017 Tax Act”). The 18.5 percent increase in 2017 from a nonrecurring deferred tax adjustment was caused by the 14 percent decrease in the highest marginal corporate rate from 35 percent to 21 percent beginning in 2018. The effect for 2017 was cumulatively added to a tax benefit calculated for that year. The 14 percent decrease is reflected in the 2018 income tax expense rate. In addition, the year-over-year but like all companies, our effective tax rate will be impacted bydecreased due to effects related to an excess tax deficiency from stock-based compensation awards, which had the effect of those permanent items consistently reported comparedincreasing the 2018 tax rate and partially offsetting the year-over-year decrease. Other nominal 2018 tax rate decreases included effects from property sales, net apportionment changes, research credits, and percentage depletion offset by the effects from limits to reported income or loss. As a result of our divestitures and acquisitions, our base rate has been decreasing over the last three years and has now settled at a rate we expect to be consistent in future periods. certain covered individual’s compensation.
Please refer to Overview of Liquidity and Capital Resources and Critical Accounting Policies and Estimates below and as well as Note 4 -– Income Taxes in Part II, Item 8 of this report for further discussion.
The increase in the effective tax rate in 2015 compared with 2014 resulted from a tax benefit effect of Oklahoma permanent tax benefits, enacted state rate changes in Texas and North Dakota, and claimed research and development credits added to the benefit created by a pre-tax loss recorded for the year ended December 31, 2015.
Overview of Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain the flexibility with regard to adjust our activity level and capital expenditures in periods of prolonged weak commodity prices or to respond should commodity prices recover further.expenditures.
Sources of Cash
We currently expect our 20172020 capital program to be funded by cash flows from operations and proceedswith any remaining cash needs being funded by borrowings under our credit facility. During the year ended December 31, 2019, we generated $823.6 million of cash flows from operating activities. As of December 31, 2019, the divestitureremaining available borrowing capacity under our Credit Agreement provided $1.1 billion in liquidity; however, our borrowing base can be adjusted as a result of properties.changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities.
Although we anticipateexpect cash flows from these sources willto be sufficient to fund our expected 20172020 capital program, we may also elect to borrow under our Credit Agreement and/or raise funds through new debt or equity financingsofferings or from other sources or enter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. Decreases in commodity prices have limited our industry’s access to capital markets in recent periods.of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly-issued securities may have rights, preferences, or privileges senior to those of existing stockholders. During the first quarter of 2016,Future downgrades in our credit ratings were downgraded by two major rating agencies. These downgrades and any future downgrades maycould make it more difficult or expensive for us to borrow additional funds. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. All of our sources of liquidity can be impactedaffected by the general conditionconditions of the broader economy, force majeure events, and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry. Our Credit Agreement borrowing base could be further reduced as a result of lower commodity prices, divestitures of proved properties, or newly issued debt. See Credit Agreement below for a discussion of recent changes to our borrowing base and the expected reduction as part of the upcoming redetermination process.
We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. During 2016, cash received from the settlement of commodity derivative contracts provided a significant positive source of cash, which is reflected in net cash provided by operating activities on our consolidated statements of cash flows. The fair value of our commodity derivative contracts was a net liability of $91.7 million at December 31, 2016. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of settlement of those contracts.
Please referThe enactment of the 2017 Tax Act reduced our highest marginal corporate tax rate for 2018 and future years from 35 percent to 21 percent, however future deductibility of interest expense may be limited. In general, the section Usesenactment of Cash below for discussion of financing activities in 2016, including the issuances of our Senior Convertible Notes and 2026 Notes, and public equity offerings, and the use of these proceeds in funding acquisition activities.
Proposals to reform the Internal Revenue Code of 1986 (“IRC”), as amended, which include eliminating or reducing current tax deductions for intangible drilling costs, depreciation of equipment acquisition costs, the domestic production activities deduction, percentage depletion, and other deductions which reduce our taxable income, have been discussed in past years. Although we believe this possibility2017 Tax Act has decreased with the recent congressional discussionshad a positive impact on tax reform, we expect that future legislation eliminating these deductions would reduce net operating cash flows, over time, thereby reducing funding available for our exploration and development capital programs, as well as funding available to our peers in the industry for similar programs. If enacted, reductions in available deductions could have a significant adverse effect on drilling in the United States for a number of years.
we believe it will positively impact future operating cash flows.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion and has ais scheduled to mature on September 28, 2023. The maturity date of December 10, 2019. As of December 31, 2016,could, however, occur earlier on August 16, 2022, if we have not completed certain repurchase, redemption, or refinancing activities associated with our borrowing base and the current aggregate lender commitments were $1.17 billion. Our borrowing base is subject to regular semi-annual redeterminations,2022 Senior Notes, as well as periodic adjustments as a result of significant transactions made by the Company. Please refer to Note 5 - Long-Term Debtoutlined in Part II, Item 8 of this report for additional discussion of changes in our borrowing capacity throughout 2016 resulting from our debt and equity issuances and our acquisitions and divestitures. The borrowing base redetermination process considers the value of both our (a) proved oil and gas properties reflected in our most recent reserve report and (b) commodity derivative contracts, each as determined by our lender group. The Sixth Amendment to the Credit Agreement revised certain of our covenants under the Credit Agreement and modified the borrowing base utilization grid. On December 1, 2016, the borrowing base was reduced as a result of closing the Raven/Bear Den asset divestiture. We expect a further reduction to our borrowing base during the next semi-annual redetermination scheduled for April 1, 2017, as a result of the anticipated sale of our outside-operated Eagle Ford shale assets, as well as the decrease in our proved reserves at December 31, 2016. We do not expect to be negatively impacted by this anticipated borrowing base reduction, as we expect to have ample cash on hand upon the closings of planned divestitures and believe the revised borrowing base amount will be sufficient to meet any other anticipated liquidity and operating needs. We had a zero outstanding balance under our Credit Agreement as of December 31, 2016.Agreement. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. Please refer to Note 5 -– Long-Term Debt in Part II, Item 8 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under our Credit Agreement as of February 15, 2017,6, 2020, December 31, 2016,2019, and December 31, 2015.2018.
The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each as determined by our lender group. The next scheduled borrowing base redetermination date is April 1, 2020.
We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company tothat we maintain certain financial ratios, as defined by the Credit Agreement. Financial covenants under the Credit Agreement require, asPlease refer to Note 5 – Long-Term Debt in Part II, Item 8 of the last day of each of the Company’s fiscal quarters,this report for additional detail regarding our (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0.financial covenants. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of December 31, 2016,2019, and through the filing date of this report. Please refer to the caption Non-GAAP Financial Measures below for the calculation of adjusted EBITDAX, and a reconciliation of adjusted EBITDAX to net income (loss) and to net cash provided by operating activities.
Our daily weighted-average credit facility debt balance was approximately $183.8 million, $253.7$115.2 million and $86.6$13.1 million for the years ended December 31, 2016, 2015,2019, and 2014,2017, respectively. We had no credit facility borrowing activity during 2018 as a result of cash on hand and cash proceeds received during 2018 from divestitures. Cash flows provided by our operating activities, divestiture proceeds, received from divestitures of properties, capital markets activities, and the amount of our capital expenditures, including acquisitions, all impact the amount we have borrowedborrow under our credit facility.
Under our Credit Agreement.Agreement, borrowings in the form of Eurodollar loans accrue interest based on the London Interbank Offered Rate (“LIBOR”). The use of LIBOR as a global reference rate is expected to be discontinued after 2021. Our Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it shall no longer be used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. We
currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business.
Weighted-Average Interest and Weighted-Average Borrowing Rates
Our weighted-average interest rates includerate includes paid and accrued interest, fees on the unused portion of the credit facility’s aggregate commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and the non-cash amortization of the discount related to the Senior Convertible Notes. Our weighted-average borrowing rates includerate includes paid and accrued interest only.
The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2016, 2015,2019, 2018, and 2014.
2017.
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Weighted-average interest rate | 6.2 | % | | 6.0 | % | | 6.5 | % | 6.4 | % | | 6.4 | % | | 6.4 | % |
| Weighted-average borrowing rate | 5.7 | % | | 5.5 | % | | 5.9 | % | 5.7 | % | | 5.8 | % | | 5.8 | % |
Our weighted-average interest rates and weighted average borrowing rates for the years ended December 31, 2016, 2015,2019, 2018, and 2014, have been2017, were impacted by the timing of Senior Notes and Senior Convertible Noteslong-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility, andfacility. Additionally, our weighted-average interest rates were impacted by the fees paid on the unused portion of our aggregate commitment.lender commitments. There was no material change in our weighted-average interest rates or weighted-average borrowing rates for the years ended December 31, 2019, 2018, and 2017. The rates disclosed in the above table for the year ended December 31, 2016, do not reflect amounts associated with the approximate $16.4 millionrepurchase of Senior Notes, such as the discount
realized or premium paid upon repurchase, of certain of our Senior Notes during 2016,or the approximate $700,000 acceleration of unamortized deferred financing costs expensed upon repurchase, or the $10.0 million fee paid to terminate an unused second lien facility. The rates disclosed for the year ended December 31, 2015, do not reflect the approximate $12.5 million premium paid for the tender offer and redemption of the 2019 Notes or the approximate $4.1 million of unamortized deferred financing costs expensed upon extinguishment of these notes during 2015.repurchase. Please refer to Note 5 -– Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Uses of Cash
We use cash for the acquisition,development, exploration, and developmentacquisition of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the acquisition,development, exploration, and developmentacquisition of oil and gas properties are the primary use of our capital resources. During 2016,2019, we spent $2.8approximately $1.0 billion inon capital expenditures and in acquiring proved and unproved oil and gas properties. These amounts differexpenditures. This amount slightly differs from the costs incurred amounts, which areamount as costs incurred is an accrual-based and includeamount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts,amounts. Please refer to Costs Incurred in Oil and the fair valueGas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of the equity consideration given to the sellers of the QStar Acquisition.this report for additional discussion.
The amount and allocation of our future capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities,acquisitions, our cash flows from operating, investing, and financing activities, and our ability to assimilate acquisitions and execute our drillingdevelopment program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing and results of our operated and outside-operated exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget to assess changes in current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors.
We may from time to time repurchase certain amountsor redeem all or portions of our outstanding debt securities for cash, and/or through exchanges for other securities.securities, or a combination of both. Such repurchases or exchangesredemptions may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchangesredemptions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. Repurchases or exchangesredemptions are reviewed as part of the allocation of our capital. During 2016,the third quarter of 2018, we redeemed our 2021 Senior Notes, repurchased or redeemed all of our 2023 Senior Notes, repurchased a portion of our 2022 Senior Notes, in open marketand issued our 2027 Senior Notes. We did not conduct similar debt transactions at a discount, resulting in a $15.7 million net gain on extinguishmentduring 2019, or through the filing of debt.this report. Please refer to Note 5 -– Long-Term Debt in Part II, Item 8 of this report for additional discussion. As part of our strategy for 2017,2020, we planwill continue to reducefocus on improving our debt by repurchasing a portionmetrics, which could include reducing the amount of our Senior Notes.outstanding debt.
As of the filing date of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes, the indenture governing our Senior Convertible Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During 2016,2019, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares.shares of our common stock during 2020.
During 2016,the years ended December 31, 2019, 2018, and 2017, we paid $7.8$11.3 million, $11.2 million, and $11.1 million, respectively, in dividends to our stockholders, reflecting a dividend of $0.10 per share.share each year. Our current intention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, Credit Agreement, indentures governing our Senior Convertible Notes and Senior Convertible Notes, other covenants, and other factors which could arise. The payment and amount of future dividends remains at the discretion of our Board of Directors.
Analysis of Cash Flow Changes Between 20162019 and 20152018 and Between 20152018 and 2014
2017
The following tables present changes in cash flows between the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying consolidated statements of cash flows (“accompanying statements of cash flows”) in Part II, Item 8 of this report.
Operating Activities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, | | Amount Change Between | | Percent Change Between |
| | | 2016 | | 2015 | | 2014 | | 2016/2015 | | 2015/2014 | | 2016/2015 | | 2015/2014 |
| | | (in millions) | | | | |
| Net cash provided by operating activities | | $ | 552.8 |
| | $ | 978.4 |
| | $ | 1,456.6 |
| | $ | (425.6 | ) | | $ | (478.2 | ) | | (43 | )% | | (33 | )% |
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, | | Amount Change Between |
| | 2019 | | 2018 | | 2017 | | 2019/2018 | | 2018/2017 |
| | (in millions) |
| Net cash provided by operating activities | $ | 823.6 |
| | $ | 720.6 |
| | $ | 515.4 |
| | $ | 103.0 |
| | $ | 205.2 |
|
Derivative settlements increased $202.9 million for the year ended December 31, 2019, compared with 2018. This increase was partially offset by decreased cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes of $73.4 million, and increased cash paid for LOE and ad valorem taxes of $22.0 million for the year ended December 31, 2019, compared with 2018. Cash paid for interest decreased $8.8 million for the year ended December 31, 2019, compared with 2018, due to the redemption and repurchase of certain senior notes in the third quarter of 2018, partially offset by increased interest paid on the 2027 Senior Notes and interest paid on credit facility borrowings during the year ended December 31, 2019. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.
Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, including derivative cash settlements, decreased $588.0increased $196.0 million or 35 percent, to $1.1 billion for the year ended December 31, 2016,2018, compared with the same period in 2015. This decrease was2017, primarily as a result of an increase in our realized price, after the decline in production volumes, realized commodity prices, andeffect of derivative cash settlements. CashInterest paid for LOE in 2016 decreased $52.6$13.4 million or 21 percent, to $199.9 million compared with the same period in 2015 due primarily to a 14 percent decrease in production volumes and a reduction in service provider costs. During 2016, we paid $10.0 million to terminate a second lien facility that was not needed to fund the Rock Oil Acquisition. During 2015, we paid approximately $12.5 million associated with the premium for the tender offer and redemption of the 2019 Notes. The remaining change was related to decreases in cash G&A expense, exploration overhead, and ad valorem taxes, as well as changes in working capital balances.
Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, including derivative cash settlements, decreased $366.1 million, or 18 percent, to $1.7 billion for the year ended December 31, 2015,2018, compared with the same period in 2014. Cash paid for LOE in 2015 increased $22.2 million, or 10 percent, to $252.5 million compared with the same period in 2014, due primarily to a 16 percent increase in production volumes, partially offset by a reduction in service provider costs. Cash paid for interest, net of capitalized interest, increased $37.8 million during 2015 compared with 20142017, due to making,the redemption and repurchase of certain of our senior notes in 2015, the first interest payment on our 2022 Notes issued at the endthird quarter of 2014. Additionally, we paid approximately $12.5 million associated with the premium2018. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for the tender offer and redemption of the 2019 Notes.additional discussion.
Investing Activities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, | | Amount Change Between | | Percent Change Between |
| | | 2016 | | 2015 | | 2014 | | 2016/2015 | | 2015/2014 | | 2016/2015 | | 2015/2014 |
| | | (in millions) | | | | |
| Net cash used in investing activities | | $ | (1,870.6 | ) | | $ | (1,144.6 | ) | | $ | (2,478.7 | ) | | $ | (726.0 | ) | | $ | 1,334.1 |
| | 63 | % | | (54 | )% |
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, | | Amount Change Between |
| | 2019 | | 2018 | | 2017 | | 2019/2018 | | 2018/2017 |
| | (in millions) |
| Net cash used in investing activities | $ | (1,013.3 | ) | | $ | (587.9 | ) | | $ | (201.5 | ) | | $ | (425.4 | ) | | $ | (386.4 | ) |
Net cash used in investing activities increased for the year ended December 31, 2016,2019, compared with 2018. Proceeds received from the same periodsale of oil and gas properties were $735.5 million lower in 2015.2019 than in 2018 as no material divestitures occurred during 2019. This was partially offset by lower capital expenditures and less cash paid to acquire proved and unproved oil and gas properties of $279.4 million and $30.7 million, respectively.
Net cash used in investing activities increased for the year ended December 31, 2018, compared with 2017. Capital expenditures in 2018 increased $414.8 million compared with 2017, from $888.4 million to $1.3 billion as a result of increased drilling and completion activities. During 2016,2018, cash paid to acquire proved and unproved properties in the Midland Basin totaled $2.2 billion, whereas we had no significant acquisition activity in 2015. Netdecreased $56.6 million compared with 2017. Further, net proceeds from the sale of oil and gas properties increased $588.1decreased $28.2 million for the year ended December 31, 2016,in 2018, compared with the same period in 2015, due to2017. During 2018, net proceeds were primarily from the divestitures of our Raven/Bear Den assetsPRB Divestiture, Divide County Divestiture, and other non-core assets in 2016 exceedingHalff East Divestiture. During 2017, net proceeds were primarily from the sale of our Mid-Continent assets in 2015. Capital expenditures in 2016 decreased $863.7 million, or 58 percent, compared with 2015 as a result of reduced drilling and completion activities and lower service provider costs, as well as a significant amount of accrued 2014 drilling and completion payables paid in early 2015.outside-operated Eagle Ford shale assets.
Capital expenditures in 2015 decreased $481.2 million, or 24 percent, compared with 2014. Drilling capital incurred decreased approximately 38 percent in 2015 compared with 2014 as a result of reduced operated and non-operated rig count and lower service provider costs. Partially offsetting this decrease in capital activity was our payment, in 2015, of a significant amount of accrued drilling and completion payables at year-end 2014. Additionally, we did not have significant acquisition activity during 2015, whereas we acquired $544.6 million of proved and unproved properties in our Gooseneck prospect area and in the Powder River Basin during 2014. Net proceeds from the sale of oil and gas properties increased $314.1 million in 2015 compared with 2014 due primarily to the divestiture of our remaining Mid-Continent assets during the second quarter of 2015.
Financing Activities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, | | Amount Change Between | | Percent Change Between |
| | | 2016 | | 2015 | | 2014 | | 2016/2015 | | 2015/2014 | | 2016/2015 | | 2015/2014 |
| | | (in millions) | | | | |
| Net cash provided by financing activities | | $ | 1,327.2 |
| | $ | 166.2 |
| | $ | 740.0 |
| | $ | 1,161.0 |
| | $ | (573.8 | ) | | 699 | % | | (78 | )% |
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, | | Amount Change Between |
| | 2019 | | 2018 | | 2017 | | 2019/2018 | | 2018/2017 |
| | (in millions) |
| Net cash provided by (used in) financing activities | $ | 111.8 |
| | $ | (368.7 | ) | | $ | (12.3 | ) | | $ | 480.5 |
| | $ | (356.4 | ) |
During 2016, we received $934.1Net cash provided by (used in) financing activities increased $480.5 million of net proceeds from two public equity offerings, $491.6 million of net proceeds from our 2026 Notes issuance, and $166.6 million of net proceeds from our Senior Convertible Notes issuance. These proceeds were used to partially fund the Rock Oil and QStar acquisitions, as well as to pay down our credit facility balance. As a result, we had net repayments under our credit facility of $202.0 million duringfor year ended December 31, 2019, compared with 2018. During the year ended December 31, 2016, compared with2019, net borrowings under our credit facility increased $122.5 million. We had a zero balance on our credit facility throughout 2018 due to our cash balance resulting from the proceeds received from divestitures in the first half of $36.02018. During the year ended December 31, 2018, we redeemed or repurchased $824.6 million during 2015. During 2015,principal outstanding of certain of our senior notes, and paid premiums totaling $20.4 million in connection with these redemptions and repurchases. Additionally, we received $491.0 million ofissued our 2027 Senior Notes for net proceeds from the issuance of our 2025 Notes, which$492.1 million. There were used for the tender and redemption of the $350.0 million principal amount of our 2019 Notes. Additionally, in 2016, we paid $24.2 million for capped callno such debt transactions related to our Senior Convertible Notes and paid $29.9 million for the repurchase of $46.3 million in aggregate principal amount of a portion of our Senior Notes.during 2019. Please refer to Note 5 -– Long-Term Debt in Part II, Item 8 of this report for additional discussion.
We received $491.0 million of net proceeds from the issuance of our 2025 Notes in 2015, compared with $590.0 million of net proceeds from the issuance of our 2022 Notes during 2014. The 2015 proceeds were primarily used for the tender and redemption of our 2019 Notes. We had net borrowings under our credit facility of $36.0 million during the year ended December 31, 2015, compared with net borrowings of $166.0 million in 2014.
Interest Rate Risk
We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of December 31, 2019, we had a $122.5 million balance on our credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the credit facility’s fair market value but will not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes or fixed-rate Senior Convertible Notes but can impact their fair market values. As of December 31, 2016,2019, our outstanding principal amount of fixed-rate debt totaled $2.6 billion and our floating-rate debt outstanding totaled $3.0 billion, however, we had no floating-rate debt outstanding, thus we had no exposure to market risk related to floating interest rates at that date.$122.5 million. Please refer to Note 11 -– Fair Value Measurements in Part II, Item 8 of this report for additional discussion on the fair valuevalues of our Senior Notes and Senior Convertible Notes.
Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, overall profitability, access to capital, and future rate of growth. Oil, gas, and NGL prices are subject to wideunpredictable fluctuations in response toresulting from a variety of factors, including changes in supply and demand, and other factors.all of which are typically beyond our control. The markets for oil, gas, and NGLs have been volatile, especially over the last several years, and these markets will likely continue to be volatile in the future. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our 20162019 production, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $61.2$118.3 million, $33.7$26.3 million, and $22.9$14.0 million, respectively. If our 2016 realizedcommodity prices before the effects of derivative settlements, had been 10 percent lower, our net derivative settlements for the year ended December 31, 2019 would have been higher, partially offsettingoffset the decreasedeclines in oil, gas, and NGL production revenues quantified above.
revenue by approximately $75.9 million.
We enter into commodity derivative contracts in order to reduce the impactrisk of fluctuations in commodity prices. The fair valuesvalue of our commodity derivative contracts areis largely determined by estimates of the forward curves of the relevant price indices. AtAs of December 31, 2016,2019, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net liabilityderivative positions for these products by approximately $56$113.4 million, $47$6.4 million, and $27$3.6 million, respectively.
Schedule of Contractual Obligations
The following table summarizes our contractual obligations at December 31, 2016,2019, for the periods specified (in millions):
| | | Contractual Obligations | | Total | | Less than 1 year | | 1-3 years | | 3-5 years | | More than 5 years | | Total | | Less than 1 year | | 1-3 years | | 3-5 years | | More than 5 years |
Long-term debt (1) | | $ | 2,976.2 |
| | $ | — |
| | $ | — |
| | $ | 519.4 |
| | $ | 2,456.8 |
| | $ | 2,771.8 |
| | $ | — |
| | $ | 649.3 |
| | $ | 622.5 |
| | $ | 1,500.0 |
|
Interest payments (2) | | 1,275.8 |
| | 174.3 |
| | 351.2 |
| | 347.6 |
| | 402.7 |
| | 832.7 |
| | 160.4 |
| | 313.2 |
| | 222.4 |
| | 136.7 |
|
Delivery commitments (3) | | 970.9 |
| | 105.7 |
| | 274.9 |
| | 269.0 |
| | 321.3 |
| | 218.5 |
| | 46.3 |
| | 133.7 |
| | 32.5 |
| | 6.0 |
|
Operating leases and contracts (3) | | 87.2 |
| | 39.4 |
| | 17.7 |
| | 13.7 |
| | 16.4 |
| | 131.1 |
| | 56.3 |
| | 34.6 |
| | 21.5 |
| | 18.7 |
|
Asset retirement obligations (4) | | 161.2 |
| | 6.8 |
| | 34.8 |
| | 2.2 |
| | 117.4 |
| | 114.4 |
| | 3.1 |
| | 6.2 |
| | 36.0 |
| | 69.1 |
|
Derivative liability (5) | | 214.4 |
| | 115.6 |
| | 97.4 |
| | 1.4 |
| | — |
| |
Derivative liabilities (5) | | | 54.6 |
| | 51.1 |
| | 3.5 |
| | — |
| | — |
|
Other (6) | | 38.4 |
| | 7.9 |
| | 15.6 |
| | 14.9 |
| | — |
| | 35.6 |
| | 5.6 |
| | 14.9 |
| | 15.1 |
| | — |
|
| Total | | $ | 5,724.1 |
| | $ | 449.7 |
| | $ | 791.6 |
| | $ | 1,168.2 |
| | $ | 3,314.6 |
| | $ | 4,158.7 |
| | $ | 322.8 |
| | $ | 1,155.4 |
| | $ | 950.0 |
| | $ | 1,730.5 |
|
| |
(1) | Long-term debt consists of the $122.5 million balance on our revolving credit facility, our Senior Notes, and our Senior Convertible Notes and assumes no principal repayment until the duematurity dates of thethese instruments. The actual paymentspayment dates may vary significantly. As of December 31, 2016, we had a zero balance on our revolving credit facility. |
| |
(2) | Interest payments on our Senior Notes and Senior Convertible Notes are estimated assuming no principal repayment until the duematurity dates of thethese instruments. AsInterest payments on our credit facility have been estimated using the rate applicable to the outstanding balance was zero aton our credit facility as of December 31, 2016,2019, and assume no future borrowings or repayments until the above table reflects only the fee that would be paid on the unused credit facility’s aggregate lender commitment amount through theSeptember 28, 2023 maturity date of the Credit Agreement. The actual interest payments on our Senior Notes, Senior Convertible Notes, and our credit facility may vary significantly. |
| |
(3) | Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion.discussion regarding our operating leases, contracts, and gathering, processing, transportation throughput, and delivery commitments. The amount relating to our gathering, processing, and transportation throughput, and delivery commitments in the table above reflects the aggregate undiscounted deficiency payments assuming we delivered no product. Subsequent to December 31, 2016,This amount does not include any costs that may be incurred for certain contracts where we entered into a definitive agreementcannot predict with accuracy the amount and timing of any payments that may be incurred for not meeting certain minimum commitments, as such payments are dependent upon the saleprice of our outside-operated Eagle Ford shale assets held for saleoil in effect at December 31, 2016, and expect to close the transaction in the first quartertime of 2017, at which point we would no longer be subject to throughput commitments totaling $501.9 million of the deficiency payments presented in the table above.settlement. |
| |
(4) | Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on our accompanying consolidated balance sheets (“accompanying balance sheets”) as of December 31, 2016.2019. The timing and amount of the ultimate settlement of these obligations is unknown and can be impacted by economic factors, a change in development plans, and federal and state regulations. Obligations related to inactive wells or wells that are not economic at current commodity price levels as of December 31, 2016, are shown as an obligation in 1-3 years due to the substantial uncertainty on the timing of plugging or re-entering these wells. Please refer to Note 914 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion. |
| |
(5) | Amounts shown represent only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices as of December 31, 2016,2019, and exclude estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts presented on the accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of non-performance for us and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, as they are subject to continuing market risk and commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion. |
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(6) | The majority of this amount is related to the unfunded portion of our estimated pension liability of $37.9$35.2 million, for which we have estimated the timing of future payments based on historical annual contribution amounts. |
Off-Balance Sheet Arrangements
As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.
We evaluate our transactions to determine if any variable interest entities exist. If it is determinedwe determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions in 2016during 2019 or 2015.2018, or through the filing of this report.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant Accounting Policiesin Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.
Successful Efforts Method of Accounting. GAAPprovides for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included inNote 1 -– Summary of Significant Accounting Policiesof Part II, Item 8 of this report.
Oil and Gas Reserve Quantities. Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including the calculations of depletion and impairment of proved and unproved oil
and gas properties. Please refer to Oil and Gas Producing Activities inNote 1 – Summary of Significant Accounting Policiesof Part II, Item 8 of this report for additional discussion on our accounting policies impacted by estimated reserve quantities.
Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future net cash flows calculation requires that a 10 percent discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Ryder Scott, an independent reservoir-evaluationreservoir evaluation consulting firm, to audit at least 80 percent of our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year-end.year end. It should not be assumed that the standardized measure of discounted future net cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2016,2019, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based these measures on a 12-month average of the first-day-of-the-month prices for the year ended December 31, 2016.2019. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimates. Please refer to Risk Factors - Risks Related to Our Business in Part I, Item 1A of this report.
Our estimates of proved reserves materially impact depletion expense and impairment of proved and unproved properties. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducingwhich would reduce future earnings. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for or produce higher cost fields.net income. Changes in depletion rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Changes in depletion or impairment calculations caused by changes in reserve quantities or net cash flowsImpairments are recorded in the period the reserve estimates change.
in which they are identified.
The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.
| | | | For the Years Ended December 31, | | | | | | | | |
| | 2016 | | 2015 | | 2014 | For the Years Ended December 31, |
| | MMBOE | | MMBOE | | MMBOE | 2019 | | 2018 | | 2017 |
| | Change | | Change | | Change | MMBOE Change | | MMBOE Change | | MMBOE Change |
| Revisions resulting from performance | (18.1 | ) | | 47.3 |
| | 11.3 |
| (14.9 | ) | | (59.7 | ) | | 7.4 |
|
| Removal of proved undeveloped reserves no longer in our five-year development plan | (43.0 | ) | | (79.4 | ) | | (4.3 | ) | (9.8 | ) | | (22.6 | ) | | (13.9 | ) |
| Revisions resulting from price changes | (35.1 | ) | | (116.5 | ) | | 3.4 |
| (70.0 | ) | | 13.5 |
| | 23.1 |
|
| Total | (96.2 | ) | | (148.6 | ) | | 10.4 |
| (94.7 | ) | | (68.8 | ) | | 16.6 |
|
As previously noted, commodity prices are volatile and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes.
The CompanyWe cannot reasonably predict future commodity prices, although we believe that together, the below analyses provide reasonable information regarding the impact of changes in pricing and trends on total estimated proved reserves. The following table reflects the estimated MMBOE change and percentage change to our total reported estimated proved reserve volumes from the described hypothetical changes:
| | | | For the Year Ended December 31, 2016 | | | | | |
| | MMBOE | | Percentage | For the year ended December 31, 2019 |
| | Change | | Change | MMBOE Change | | Percentage Change |
10 percent decrease in SEC pricing (1) | (81 | ) | | (21 | )% | (7.2 | ) | | (2 | )% |
Average NYMEX strip pricing as of fiscal year end (2) | 163 |
| | 41 | % | (5.2 | ) | | (1 | )% |
10 percent decrease in proved undeveloped reserves (3) | (19 | ) | | (5 | )% | (21.5 | ) | | (5 | )% |
| |
(1) | The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated proved reserve volumes as of December 31, 2016,2019, and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs. |
| |
(2) | The change solely reflects the impact of replacing SEC pricing with the calculatedfive-year average of the five year NYMEX strip pricing for each product as of December 31, 2016. The five year average NYMEX strip prices used in the analysis were $56.192019. SEC pricing of $55.69 per Bbl for oil, $3.09$2.58 per MMBtu for gas, and $27.44$22.68 per Bbl for NGL. Other impacts modeledNGLs as of December 31, 2019, compared to the five-year average NYMEX strip pricing of $53.65 per Bbl for oil, $2.42 per MMBtu for gas, and $19.67 per Bbl for NGLs as of December 31, 2019, would result in the analysis resulting from the hypothetical improved pricing include: 1) management’s estimate of escalation in future service and equipment costs at the commodity price level noted above 2) extension of economic lives and increase in economically recoverable volumes; 3) additionala one percent decrease to our total reported estimated proved undeveloped reserve locations that pass the PV-0 hurdle; and 4) additional proved undeveloped reserve locations that could be reasonably drilled within five years given additional capital that would be available for development at the commodity price level noted above. We did not add any proved undeveloped reserve locations in our outside-operated Eagle Ford shale or Bakken/Three Forks program in Divide County, North Dakota given our intent to sell these properties in 2017.volumes. |
| |
(3) | The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2016,2019, and does not include any additional impacts to our estimated proved reserves. |
Additional reserve information can be found in the Reserves section in Part I, Items 1 and 2 of this report, and in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
Impairment of Oil and Gas Properties. Proved properties are evaluated periodically for impairment on a pool-by-pool basis and when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value (or discounted future cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs, development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows projects.flows.
Unproved oil and gas properties are evaluated periodically for impairment on a prospect-by-prospect basis and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and our intent to renew leases. We estimate the fair value of unproved properties using a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by us or other market participants. Unproved oil and gas properties are impaired when we determine that the property will not be developed or the carrying value will not be realized.
Proved and unproved oil and gas properties are classified as held for sale when we commit to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell.
We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any amount of future impairment being difficult to predict, based on updatedour commodity price assumptions as of February 15, 2017,6, 2020, we do not expect any material property impairments on assets held for use in the first quarter of 2017 due to2020 resulting from commodity price impacts. We do, however, anticipate recognizing an impairment in the first quarter of 2017 upon the reclassification of our remaining Williston Basin assets in Divide County, North Dakota as assets held for sale. We announced the plan to sell these assets subsequent to December 31, 2016. At year-end 2016, the estimated undiscounted cash flows for the Divide County assets exceeded the carrying amount. Based on preliminary estimates of fair value less costs to sell, we expect an impairment in the range of $200 million to $400 million to be recorded in the first quarter of 2017.
Please refer to Note 1 -– Summary of Significant Accounting Policiesand Note 11 -– Fair Value Measurements in Part II, Item 8 of this report for discussion of impairments of oil and gas properties and other property and equipment recorded for the years ended December 31, 2016, 2015,2019, 2018, and 2014.2017.
Purchase Price Allocation. Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities acquired based on their estimated fair value as of the acquisition date. Various assumptions are made when estimating fair values assigned to proved and unproved oil and gas properties including: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgment by management at the time of the valuation.
Asset Retirement Obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells and our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the cost, estimate the economic lives and timing of abandonment of our properties, estimate future inflation rates, and determine whatthe appropriate credit-adjusted risk-free discount rate to use. The impact to the accompanying consolidated statements of operations from these estimates is reflected in our depletion, depreciation, and amortization calculations and occurs over the remaining life of our respective oil and gas properties. Please refer to Note 914 – Asset Retirement Obligationsin Part II, Item 8 of this report for additional discussion.
Revenue Recognition. Effective January 1, 2018, our revenue recognition policy was updated to reflect the adoption of new accounting guidance. Our revenue recognition policy is a critical accounting policy because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. We derive ourOur primary source of revenue primarily fromis derived by the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when our production is deliveredcustody and title (“control”) of the product, as defined by contractual terms, transfers to the purchaser, but paymentpurchaser. Payment for these sales is generallytypically received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month, we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, contractual arrangements, their historical performance, NYMEX, local spot market, and OPIS prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are
recorded in the month payment is received. A 10 percent change in our year-end revenue accrual at year end 2019 would have impacted total operating revenues by approximately $10$14.6 million in 2016.2019. Please refer to Note 2 - Revenue from Contracts with Customersin Part II, Item 8 of this report for additional discussion.
Derivative Financial Instruments. We periodically enter into commodity derivative contracts to manage our exposure to oil, gas, and NGL price volatility.volatility and location differentials. We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive loss.income (loss). The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values we report in our consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. Please refer to Note 1 – Summary of Significant Accounting PoliciesandNote 10 – Derivative Financial Instrumentsin Part II, Item 8 of this report for additional discussion.
Income Taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our consolidated financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are
recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. A one percent change in our effective tax rate would have changed our calculated income tax benefitexpense by approximately $12$2.3 million for the year ended December 31, 2016.2019. Please refer to Note 1 – Summary of Significant Accounting PoliciesandNote 4 – Income Taxesin Part II, Item 8 of this report for additional discussion.
Accounting Matters
Please refer to the section entitled Recently Issued Accounting Standards under inNote 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional information on the recent adoption of new authoritative accounting guidance.
Environmental
We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations.
Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, see please refer to Risk Factors – Risks Related to Our Business – Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing, air quality, and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.
Climate Change. In June 2013, President Obama announced a Climate Action Plan designed to further reduce greenhouse gasGHG emissions and prepare the nation for the physical effects that may occur as a result of climate change. The Climate Action Plan targetstargeted methane reductions from the oil and gas sector as part of a comprehensive interagency methane strategy. On January 14, 2015,As part of the Obama Administration announced additional steps to reduce methane emissions from the oil and gas sector by 40 to 45 percent by 2025. Pursuant to this commitment,Climate Action Plan, on May 12, 2016, the EPA issued final regulations that amend and expand the 2012 regulations for the oil and gas sector by setting emission limits for greenhouse gases, or GHGs,VOCs and methane, a GHG, and added requirements for previously unregulated sources. The 2016 NSPS requires reduction of greenhouse gases in the form of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September 18, 2015. The final regulation requires, among other things, greenhouse gasGHG and VOC emission limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and natural gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of greenhouse gasesGHGs and VOCs from well completions. Both the 2012 and 2016 rules are the subjectssubject of Petitions for Review before the U.S. Circuit Court of Appeals for the District of Columbia.Columbia, although the litigation of both rules has been stayed. In October 2018, the EPA proposed scaling back provisions of the 2016 NSPS directed toward cutting leaks of methane, including proposing allowing only annual inspections for many sites. The rule does not extend to existing sources and the Trump EPA has not indicated when it will proposerescinded the Information Collection Request that was intended to gather information to develop existing source standards. Additionally,On August 29, 2019, the EPA proposed amendments to the 2012 and 2016 NSPS that would remove transmission and storage infrastructure from regulation of methane emissions and other VOCs. The amendments would also rescind methane requirements for oil and gas production and processing equipment. As an alternative, the EPA proposed to rescind the methane requirements for oil and gas altogether and sought comment on alternative interpretations of its authority to regulate pollutants under Section 111 of the Clean Air Act. On November 16, 2016, the Bureau of Land ManagementBLM finalized regulations to address methane emissions from oil and gas operations on federal and tribal lands, as part of President Obama’s Climate Action Plan. The regulations named the Methane and Waste Prevention Rule, iswere intended to
reduce the waste of natural gas from flaring, venting, and leaks by oil and gas production. The rule includesincluded requirements that prohibits venting of gas except in limited circumstances and limits flaring of gas and includes requirements for leak detection and repair. The rule also increasesincreased royalty payments for “waste” gas that is released in contravention of the rule requirements. TheAfter continuous court challenges, the BLM issued a final rule in September 2018 that rescinded most of the 2016 rule, including most of the methane control requirements. Any future regulations requiring similar capture standards may increase our operational costs, or restrict our production, which was immediately challenged in federal district court, faces an uncertain future in the Trump Administrationcould materially and is a targetadversely affect our financial condition, results of rescission through the Congressional Review Act.operations, and cash flows.
In August of 2015, the EPA finalized existing source performance standards as stringent state emission “goals” for utilities to reduce greenhouse gasGHG emissions. The proposed standards focus on re-dispatching electricity from coal-fired units to natural gas combined cycle plants and renewables. In February 2016, however, the Supreme Court stayed these rules pending judicial review andreview. The EPA has proposed a repeal of the rule is expected to be significantly weakened or rescinded bybased on a new legal interpretation of the Trump Administration.EPA’s authority. The EPA proposed a replacement rule, the Affordable Clean Energy Rule, in August 2018 and finalized the rule in June 2019.
In addition, theThe United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gasesGHGs and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gasesGHGs primarily through the planned development of greenhouse gasGHG emission inventories and/or regional greenhouse gasGHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gasGHG emission reduction goal. In addition, there have been international conventions and efforts to establish standards for the reduction of GHGs globally, including the Paris accords in December 2015. The conditions for entry into force of the
Paris accords were met on October 5, 2016 and the Agreement went into force 30 days later on November 4, 2016. However, in August 2017, the U.S. notified the United Nations Secretary-General that it intends to withdraw from the agreement as soon as it is able to do so, or November 2019. On November 4, 2019, President Trump formally notified the United Nations that the United States would withdraw from the Paris Agreement. The November 4, 2019 formal notice triggered the start of a year-long withdrawal process.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gasesGHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gasesGHGs could have an adverse effect on our business, financial condition, and results of operations. Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gasesGHGs in the earth’s atmosphere may produce climate changes that likely have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. If any suchSuch effects were to occur, they could have an adverse effect on our financial condition and results of operations.
In terms of opportunities, the regulation of greenhouse gasGHG emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation could reduce the overall demand for the oil and natural gas that we produce, the relative demand for natural gas may increase because the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, natural gas may become a more attractive transportation fuel. Approximately 4438 percent and 4539 percent of our production on a BOE basis in 20162019 and 2015,2018, respectively, was natural gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could also benefit us through the potential to obtain greenhouse gasGHG emission allowances or offsets from or government incentives for the sequestration of carbon dioxide.
Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, other non-operatinginterest income, or expense, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property impairments,abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, gains and losses on divestitures, gains orand losses on extinguishment of debt, and materials inventory impairments.certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-timenon-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for development, exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debtthe Credit Agreement section in Part II, Item 8Overview of this report.Liquidity and Capital Resources above. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failfailed to comply with the covenants that establish a maximum permitted ratio of senior securedtotal funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, and a minimum permitted ratio of adjusted EBITDAX to interest, we willwould be in default, an event that would prevent us from borrowing under our credit facility and would therefore materially limit our sources of liquidity. In addition, if we are in default under our credit facility and are unable to obtain a waiver of that default from our lenders, lenders under thatthe credit facility and under the indentures governing our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for default.
The following table provides reconciliations of our net income (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented: | | | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| | | (in thousands) | (in thousands) |
| Net income (loss) (GAAP) | Net income (loss) (GAAP) | $ | (757,744 | ) | | $ | (447,710 | ) | | $ | 666,051 |
| $ | (187,001 | ) | | $ | 508,407 |
| | $ | (160,843 | ) |
| | Interest expense | 158,685 |
| | 128,149 |
| | 98,554 |
| |
| | Other non-operating (income) expense, net | (362 | ) | | (649 | ) | | 2,561 |
| |
| | Income tax expense (benefit) | (444,172 | ) | | (275,151 | ) | | 398,648 |
| |
| | Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 790,745 |
| | 921,009 |
| | 767,532 |
| |
| | Exploration (1) | 59,194 |
| | 113,158 |
| | 122,577 |
| |
| | Impairment of proved properties | 354,614 |
| | 468,679 |
| | 84,480 |
| |
| | Abandonment and impairment of unproved properties | 80,367 |
| | 78,643 |
| | 75,638 |
| |
| | Impairment of other property and equipment | — |
| | 49,369 |
| | — |
| |
| | Stock-based compensation expense | 26,897 |
| | 27,467 |
| | 32,694 |
| |
| | Net derivative (gain) loss | 250,633 |
| | (408,831 | ) | | (583,264 | ) | |
| | Derivative settlement gain (2) | 329,478 |
| | 512,566 |
| | 12,615 |
| |
| | Change in Net Profits Plan liability | (7,200 | ) | | (19,525 | ) | | (29,849 | ) | |
| | Net gain on divestiture activity | (37,074 | ) | | (43,031 | ) | | (646 | ) | |
| | (Gain) loss on extinguishment of debt | (15,722 | ) | | 16,578 |
| | — |
| |
| | Materials inventory impairment | 2,436 |
| | 4,054 |
| | — |
| |
| Adjusted EBITDAX (Non-GAAP) | 790,775 |
| | 1,124,775 |
| | 1,647,591 |
| |
| | Interest expense | (158,685 | ) | | (128,149 | ) | | (98,554 | ) | |
| | Other non-operating income (expense), net | 362 |
| | 649 |
| | (2,561 | ) | |
| | Income tax (expense) benefit | 444,172 |
| | 275,151 |
| | (398,648 | ) | |
| | Exploration (1) | (59,194 | ) | | (113,158 | ) | | (122,577 | ) | |
| | Exploratory dry hole expense | (16 | ) | | 36,612 |
| | 44,427 |
| |
| | Amortization of discount and deferred financing costs | 9,938 |
| | 7,710 |
| | 6,146 |
| |
| | Deferred income taxes | (448,643 | ) | | (276,722 | ) | | 397,780 |
| |
| | Plugging and abandonment | (6,214 | ) | | (7,496 | ) | | (8,796 | ) | |
| | Loss on extinguishment of debt | — |
| | (12,455 | ) | | — |
| |
| | Other, net | 1,063 |
| | 9,707 |
| | 1,069 |
| |
| | Changes in current assets and liabilities | (20,754 | ) | | 61,728 |
| | (9,302 | ) | |
| Interest expense | | 159,102 |
| | 160,906 |
| | 179,257 |
|
| Income tax expense (benefit) | | (44,043 | ) | | 143,370 |
| | (182,970 | ) |
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | | 823,798 |
| | 665,313 |
| | 557,036 |
|
Exploration (1) | | 46,995 |
| | 49,627 |
| | 48,413 |
|
| Impairment of oil and gas properties | | 33,842 |
| | 49,889 |
| | 16,078 |
|
| Stock-based compensation expense | | 24,318 |
| | 23,908 |
| | 22,700 |
|
| Net derivative (gain) loss | | 97,539 |
| | (161,832 | ) | | 26,414 |
|
| Derivative settlement gain (loss) | | 39,222 |
| | (135,803 | ) | | 21,234 |
|
| Net (gain) loss on divestiture activity | | (862 | ) | | (426,917 | ) | | 131,028 |
|
| Loss on extinguishment of debt | | — |
| | 26,740 |
| | 35 |
|
| Other, net | | 481 |
| | (3,214 | ) | | 4,852 |
|
| Adjusted EBITDAX (non-GAAP) | | 993,391 |
| | 900,394 |
| | 663,234 |
|
| Interest expense | | (159,102 | ) | | (160,906 | ) | | (179,257 | ) |
| Income tax (expense) benefit | | 44,043 |
| | (143,370 | ) | | 182,970 |
|
Exploration (1) | | (46,995 | ) | | (49,627 | ) | | (48,413 | ) |
| Amortization of debt discount and deferred financing costs | | 15,474 |
| | 15,258 |
| | 16,276 |
|
| Deferred income taxes | | (41,835 | ) | | 141,708 |
| | (192,066 | ) |
| Other, net | | 1,739 |
| | 3,501 |
| | 3,033 |
|
| Changes in current assets and liabilities | | 16,852 |
| | 13,671 |
| | 69,613 |
|
| Net cash provided by operating activities (GAAP) | Net cash provided by operating activities (GAAP) | $ | 552,804 |
| | $ | 978,352 |
| | $ | 1,456,575 |
| $ | 823,567 |
| | $ | 720,629 |
| | $ | 515,390 |
|
| |
(1) | Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense. |
| |
(2)
| Derivative settlement gain for the years ended December 31, 2015, and 2014, includes $15.3 million and $5.6 million, respectively, of gains on the early settlement of futures contracts as a result of divesting our Mid-Continent assets. |
| |
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk in Item 7 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place under in Note 10 – Derivative Financial Instrumentsin Part II, Item 8 of this report and is incorporated herein by reference.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
TheTo the Stockholders and the Board of Directors and Stockholders of SM Energy Company and subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the Company) as of December 31, 20162019 and 2015, and2018, the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2016. These2019, and the related notes (collectively referred to as the “consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States)statements”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of SM Energythe Company and subsidiaries at December 31, 20162019 and 2015,2018, and the consolidated results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2016,2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), SM Energy Company and subsidiaries’the Company’s internal control over financial reporting as of December 31, 2016,2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 23, 201720, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Depletion, depreciation and amortization (‘DD&A’) of proved oil and gas properties
|
| |
| Description of the Matter | At December 31, 2019, the net book value of the Company’s proved oil and gas properties was $4.8 billion, and depletion, depreciation and amortization (DD&A) expense was $823.8 million for the year then ended. As described in Note 1 to the consolidated financial statements, under the successful efforts method of accounting, the costs of development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field are depleted as a group of assets using the units-of-production method based on proved developed oil and gas reserves, as estimated by the Company’s engineering technical team. Similarly, proved leasehold costs are depleted on the same group asset basis; however, the units-of-production method is based on total proved oil and gas reserves, as estimated by the Company’s engineering technical team. Significant judgment is required by the Company’s engineering technical team in evaluating geoscience and engineering data when estimating proved oil and gas reserves. Estimating reserves also requires the use of inputs, including oil and gas prices and operating and capital costs assumptions, among others. Because of the complexity involved in estimating oil and gas reserves, management used an independent petroleum engineering consulting firm to audit the estimates prepared by the Company’s engineering technical team for at least 80% of the Company’s total calculated proved reserve PV-10 as of December 31, 2019. Auditing the Company’s DD&A calculation is especially complex and judgmental because of our use of the work of the Company’s engineering technical team and independent petroleum engineering consulting firm and the evaluation of management’s determination of the inputs described above used by the engineering technical team and independent petroleum engineering consulting firm in estimating proved oil and gas reserves. |
|
| |
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the Company’s engineering technical team and independent petroleum engineering consulting firm for use in estimating the proved oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the engineering technical team primarily responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineering consulting firm used to audit the estimates. In addition, in assessing whether we can use the work of the Company’s engineering technical team and independent petroleum engineering consulting firm we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineering technical team and independent petroleum engineering consulting firm in estimating proved oil and gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved oil and gas reserve amounts used to the Company’s reserve report. |
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2012.
Denver, Colorado
February 23, 201720, 2020
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share amounts)data) |
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 10 |
| | $ | 77,965 |
|
| Accounts receivable | 184,732 |
| | 167,536 |
|
| Derivative assets | 55,184 |
| | 175,130 |
|
| Prepaid expenses and other | 12,708 |
| | 8,632 |
|
| Total current assets | 252,634 |
| | 429,263 |
|
| Property and equipment (successful efforts method): | | | |
| Proved oil and gas properties | 8,934,020 |
| | 7,278,362 |
|
| Accumulated depletion, depreciation, and amortization | (4,177,876 | ) | | (3,417,953 | ) |
| Unproved oil and gas properties | 1,005,887 |
| | 1,581,401 |
|
| Wells in progress | 118,769 |
| | 295,529 |
|
| Other property and equipment, net of accumulated depreciation of $64,032 and $57,102, respectively | 72,848 |
| | 93,826 |
|
| Total property and equipment, net | 5,953,648 |
| | 5,831,165 |
|
| Noncurrent assets: | | | |
| Derivative assets | 20,624 |
| | 58,499 |
|
| Other noncurrent assets | 65,326 |
| | 33,935 |
|
| Total noncurrent assets | 85,950 |
| | 92,434 |
|
| Total assets | $ | 6,292,232 |
| | $ | 6,352,862 |
|
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable and accrued expenses | $ | 402,008 |
| | $ | 403,199 |
|
| Derivative liabilities | 50,846 |
| | 62,853 |
|
| Other current liabilities | 19,189 |
| | — |
|
| Total current liabilities | 472,043 |
| | 466,052 |
|
| Noncurrent liabilities: | | | |
| Revolving credit facility | 122,500 |
| | — |
|
| Senior Notes, net of unamortized deferred financing costs | 2,453,035 |
| | 2,448,439 |
|
| Senior Convertible Notes, net of unamortized discount and deferred financing costs | 157,263 |
| | 147,894 |
|
| Asset retirement obligations | 84,134 |
| | 91,859 |
|
| Deferred income taxes | 189,386 |
| | 223,278 |
|
| Derivative liabilities | 3,444 |
| | 12,496 |
|
| Other noncurrent liabilities | 61,433 |
| | 42,522 |
|
| Total noncurrent liabilities | 3,071,195 |
| | 2,966,488 |
|
| | | | |
| Commitments and contingencies (note 6) |
| |
|
| | | | |
| Stockholders’ equity: | | | |
| Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,987,952 and 112,241,966 shares, respectively | 1,130 |
| | 1,122 |
|
| Additional paid-in capital | 1,791,596 |
| | 1,765,738 |
|
| Retained earnings | 967,587 |
| | 1,165,842 |
|
| Accumulated other comprehensive loss | (11,319 | ) | | (12,380 | ) |
| Total stockholders’ equity | 2,748,994 |
| | 2,920,322 |
|
| Total liabilities and stockholders’ equity | $ | 6,292,232 |
| | $ | 6,352,862 |
|
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 9,372 |
| | $ | 18 |
|
| Accounts receivable | 151,950 |
| | 134,124 |
|
| Derivative asset | 54,521 |
| | 367,710 |
|
| Prepaid expenses and other | 8,799 |
| | 17,137 |
|
| Total current assets | 224,642 |
| | 518,989 |
|
| | | | |
| Property and equipment (successful efforts method): | | | |
| Proved oil and gas properties | 5,700,418 |
| | 7,606,405 |
|
| Less - accumulated depletion, depreciation, and amortization | (2,836,532 | ) | | (3,481,836 | ) |
| Unproved oil and gas properties | 2,471,947 |
| | 284,538 |
|
| Wells in progress | 235,147 |
| | 387,432 |
|
| Oil and gas properties held for sale, net | 372,621 |
| | 641 |
|
| Other property and equipment, net of accumulated depreciation of $42,882 and $32,956, respectively | 137,753 |
| | 153,100 |
|
| Total property and equipment, net | 6,081,354 |
| | 4,950,280 |
|
| | | | |
| Noncurrent assets: | | | |
| Derivative asset | 67,575 |
| | 120,701 |
|
| Other noncurrent assets | 19,940 |
| | 31,673 |
|
| Total other noncurrent assets | 87,515 |
| | 152,374 |
|
| Total Assets | $ | 6,393,511 |
| | $ | 5,621,643 |
|
| | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable and accrued expenses | $ | 299,708 |
| | $ | 302,517 |
|
| Derivative liability | 115,464 |
| | 8 |
|
| Total current liabilities | 415,172 |
| | 302,525 |
|
| | | | |
| Noncurrent liabilities: | | | |
| Revolving credit facility | — |
| | 202,000 |
|
| Senior Notes, net of unamortized deferred financing costs | 2,766,719 |
| | 2,315,970 |
|
| Senior Convertible Notes, net of unamortized discount and deferred financing costs | 130,856 |
| | — |
|
| Asset retirement obligation | 96,134 |
| | 137,284 |
|
| Asset retirement obligation associated with oil and gas properties held for sale | 26,241 |
| | 241 |
|
| Deferred income taxes | 315,672 |
| | 758,279 |
|
| Derivative liability | 98,340 |
| | — |
|
| Other noncurrent liabilities | 47,244 |
| | 52,943 |
|
| Total noncurrent liabilities | 3,481,206 |
| | 3,466,717 |
|
| | | | |
| Commitments and contingencies (note 6) |
| |
|
| | | | |
| Stockholders’ equity: | | | |
| Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,257,500 and 68,075,700 shares, respectively | 1,113 |
| | 681 |
|
| Additional paid-in capital | 1,716,556 |
| | 305,607 |
|
| Retained earnings | 794,020 |
| | 1,559,515 |
|
| Accumulated other comprehensive loss | (14,556 | ) | | (13,402 | ) |
| Total stockholders’ equity | 2,497,133 |
| | 1,852,401 |
|
| Total Liabilities and Stockholders’ Equity | $ | 6,393,511 |
| | $ | 5,621,643 |
|
The accompanying notes are an integral part of these consolidated financial statements.
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)data)
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Operating revenues and other income: | | | | | | | | | | |
| Oil, gas, and NGL production revenue | $ | 1,178,426 |
| | $ | 1,499,905 |
| | $ | 2,481,544 |
| $ | 1,585,750 |
| | $ | 1,636,357 |
| | $ | 1,253,783 |
|
| Net gain on divestiture activity | 37,074 |
| | 43,031 |
| | 646 |
| |
| Marketed gas system revenue | — |
| | 9,485 |
| | 24,897 |
| |
| Net gain (loss) on divestiture activity | | 862 |
| | 426,917 |
| | (131,028 | ) |
| Other operating revenues | 1,950 |
| | 4,544 |
| | 15,220 |
| 3,493 |
| | 3,798 |
| | 6,621 |
|
| Total operating revenues and other income | 1,217,450 |
| | 1,556,965 |
| | 2,522,307 |
| 1,590,105 |
| | 2,067,072 |
| | 1,129,376 |
|
| | | | | | | |
| Operating expenses: | | | | | | | | | | |
| Oil, gas, and NGL production expense | 597,565 |
| | 723,633 |
| | 715,878 |
| 500,709 |
| | 487,367 |
| | 507,906 |
|
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 790,745 |
| | 921,009 |
| | 767,532 |
| 823,798 |
| | 665,313 |
| | 557,036 |
|
| Exploration | 65,641 |
| | 120,569 |
| | 129,857 |
| 51,500 |
| | 55,166 |
| | 54,713 |
|
| Impairment of proved properties | 354,614 |
| | 468,679 |
| | 84,480 |
| |
| Abandonment and impairment of unproved properties | 80,367 |
| | 78,643 |
| | 75,638 |
| |
| Impairment of other property and equipment | — |
| | 49,369 |
| | — |
| |
| Impairment of oil and gas properties | | 33,842 |
| | 49,889 |
| | 16,078 |
|
| General and administrative | 126,428 |
| | 157,668 |
| | 167,103 |
| 132,797 |
| | 116,504 |
| | 117,283 |
|
| Change in Net Profits Plan liability | (7,200 | ) | | (19,525 | ) | | (29,849 | ) | |
| Net derivative (gain) loss | 250,633 |
| | (408,831 | ) | | (583,264 | ) | 97,539 |
| | (161,832 | ) | | 26,414 |
|
| Marketed gas system expense | — |
| | 13,922 |
| | 24,460 |
| |
| Other operating expenses | 17,972 |
| | 30,612 |
| | 4,658 |
| |
| Other operating expenses, net | | 19,888 |
| | 18,328 |
| | 13,667 |
|
| Total operating expenses | 2,276,765 |
| | 2,135,748 |
| | 1,356,493 |
| 1,660,073 |
| | 1,230,735 |
| | 1,293,097 |
|
| | | | | | | |
| Income (loss) from operations | (1,059,315 | ) | | (578,783 | ) | | 1,165,814 |
| (69,968 | ) | | 836,337 |
| | (163,721 | ) |
| | | | | | | |
| Non-operating income (expense): | | | | | | |
| Interest expense | (158,685 | ) | | (128,149 | ) | | (98,554 | ) | (159,102 | ) | | (160,906 | ) | | (179,257 | ) |
| Gain (loss) on extinguishment of debt | 15,722 |
| | (16,578 | ) | | — |
| |
| Other, net | 362 |
| | 649 |
| | (2,561 | ) | |
| | | | | | | |
| Loss on extinguishment of debt | | — |
| | (26,740 | ) | | (35 | ) |
| Other non-operating income (expense), net | | (1,974 | ) | | 3,086 |
| | (800 | ) |
| Income (loss) before income taxes | (1,201,916 | ) | | (722,861 | ) | | 1,064,699 |
| (231,044 | ) | | 651,777 |
| | (343,813 | ) |
| Income tax (expense) benefit | 444,172 |
| | 275,151 |
| | (398,648 | ) | 44,043 |
| | (143,370 | ) | | 182,970 |
|
| | | | | | | |
| Net income (loss) | $ | (757,744 | ) | | $ | (447,710 | ) | | $ | 666,051 |
| $ | (187,001 | ) | | $ | 508,407 |
| | $ | (160,843 | ) |
| | | | | | | | | | | |
| Basic weighted-average common shares outstanding | 76,568 |
| | 67,723 |
| | 67,230 |
| 112,544 |
| | 111,912 |
| | 111,428 |
|
| Diluted weighted-average common shares outstanding | 76,568 |
| | 67,723 |
| | 68,044 |
| 112,544 |
| | 113,502 |
| | 111,428 |
|
| Basic net income (loss) per common share | $ | (9.90 | ) | | $ | (6.61 | ) | | $ | 9.91 |
| $ | (1.66 | ) | | $ | 4.54 |
| | $ | (1.44 | ) |
| Diluted net income (loss) per common share | $ | (9.90 | ) | | $ | (6.61 | ) | | $ | 9.79 |
| $ | (1.66 | ) | | $ | 4.48 |
| | $ | (1.44 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Net income (loss) | $ | (757,744 | ) | | $ | (447,710 | ) | | $ | 666,051 |
| $ | (187,001 | ) | | $ | 508,407 |
| | $ | (160,843 | ) |
| Other comprehensive loss, net of tax: | | | | | | |
| Other comprehensive income, net of tax: | | | | | | |
Pension liability adjustment (1) | (1,154 | ) | | (2,090 | ) | | (5,896 | ) | 1,061 |
| | 4,378 |
| | 767 |
|
| Total other comprehensive loss, net of tax | (1,154 | ) | | (2,090 | ) | | (5,896 | ) | |
| Total other comprehensive income, net of tax | | 1,061 |
| | 4,378 |
| | 767 |
|
| Total comprehensive income (loss) | $ | (758,898 | ) | | $ | (449,800 | ) | | $ | 660,155 |
| $ | (185,940 | ) | | $ | 512,785 |
| | $ | (160,076 | ) |
| |
(1) | ReferPlease refer to Note 1 - Summary of Significant Accounting Policies 8 – Pension Benefitsfor detail ofadditional discussion on the pension amount reclassified to general and administrative expense on the Company’s consolidated statements of operations.liability adjustment.
|
The accompanying notes are an integral part of these consolidated financial statements.
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands, except share amounts)data and dividends per share)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Additional Paid-in Capital | | | | | | | | Accumulated Other Comprehensive Loss | | Total Stockholders’ Equity |
| | Common Stock | | | Treasury Stock | | Retained Earnings | | |
| | Shares | | Amount | | | Shares | | Amount | | | |
| Balances, January 1, 2014 | 67,078,853 |
| | $ | 671 |
| | $ | 257,720 |
| | (22,412 | ) | | $ | (823 | ) | | $ | 1,354,669 |
| | $ | (5,416 | ) | | $ | 1,606,821 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 666,051 |
| | — |
| | 666,051 |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (5,896 | ) | | (5,896 | ) |
| Cash dividends, $ 0.10 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (6,723 | ) | | — |
| | (6,723 | ) |
| Issuance of common stock under Employee Stock Purchase Plan | 83,136 |
| | 1 |
| | 4,060 |
| | — |
| | — |
| | — |
| | — |
| | 4,061 |
|
| Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | 256,718 |
| | 3 |
| | (10,627 | ) | | — |
| | — |
| | — |
| | — |
| | (10,624 | ) |
| Issuance of common stock upon stock option exercises | 39,088 |
| | — |
| | 816 |
| | — |
| | — |
| | — |
| | — |
| | 816 |
|
| Stock-based compensation expense | 5,265 |
| | — |
| | 31,871 |
| | 22,412 |
| | 823 |
| | — |
| | — |
| | 32,694 |
|
| Other income tax expense | — |
| | — |
| | (545 | ) | | — |
| | — |
| | — |
| | — |
| | (545 | ) |
| Balances, December 31, 2014 | 67,463,060 |
| | $ | 675 |
| | $ | 283,295 |
| | — |
| | $ | — |
| | $ | 2,013,997 |
| | $ | (11,312 | ) | | $ | 2,286,655 |
|
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (447,710 | ) | | — |
| | (447,710 | ) |
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2,090 | ) | | (2,090 | ) |
| Cash dividends, $ 0.10 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (6,772 | ) | | — |
| | (6,772 | ) |
| Issuance of common stock under Employee Stock Purchase Plan | 197,214 |
| | 2 |
| | 4,842 |
| | — |
| | — |
| | — |
| | — |
| | 4,844 |
|
| Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | 375,523 |
| | 4 |
| | (8,682 | ) | | — |
| | — |
| | — |
| | — |
| | (8,678 | ) |
| Stock-based compensation expense | 39,903 |
| | — |
| | 27,467 |
| | — |
| | — |
| | — |
| | — |
| | 27,467 |
|
| Other income tax expense | — |
| | — |
| | (1,315 | ) | | — |
| | — |
| | — |
| | — |
| | (1,315 | ) |
| Balances, December 31, 2015 | 68,075,700 |
| | $ | 681 |
| | $ | 305,607 |
| | — |
| | $ | — |
| | $ | 1,559,515 |
| | $ | (13,402 | ) | | $ | 1,852,401 |
|
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (757,744 | ) | | — |
| | (757,744 | ) |
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1,154 | ) | | (1,154 | ) |
| Cash dividends, $ 0.10 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (7,751 | ) | | — |
| | (7,751 | ) |
| Issuance of common stock under Employee Stock Purchase Plan | 218,135 |
| | 2 |
| | 4,196 |
| | — |
| | — |
| | — |
| | — |
| | 4,198 |
|
| Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | 199,243 |
| | 2 |
| | (2,356 | ) | | — |
| | — |
| | — |
| | — |
| | (2,354 | ) |
| Stock-based compensation expense | 53,473 |
| | 1 |
| | 26,896 |
| | — |
| | — |
| | — |
| | — |
| | 26,897 |
|
| Issuance of common stock from stock offerings, net of tax | 42,710,949 |
| | 427 |
| | 1,382,666 |
| | — |
| | — |
| | — |
| | — |
| | 1,383,093 |
|
| Equity component of 1.50% Senior Convertible Notes due 2021 issuance, net of tax | — |
| | — |
| | 33,575 |
| | — |
| | — |
| | — |
| | — |
| | 33,575 |
|
| Purchase of capped call transactions | — |
| | — |
| | (24,195 | ) | | — |
| | — |
| | — |
| | — |
| | (24,195 | ) |
| Other income tax expense | — |
| | — |
| | (9,833 | ) | | — |
| | — |
| | — |
| | — |
| | (9,833 | ) |
| Balances, December 31, 2016 | 111,257,500 |
| | $ | 1,113 |
| | $ | 1,716,556 |
| | — |
| | $ | — |
| | $ | 794,020 |
| | $ | (14,556 | ) | | $ | 2,497,133 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Additional Paid-in Capital | | | | Accumulated Other Comprehensive Loss | | Total Stockholders’ Equity |
| | Common Stock | | | Retained Earnings | | |
| | Shares | | Amount | | | | |
| Balances, January 1, 2017 | 111,257,500 |
| | $ | 1,113 |
| | $ | 1,716,556 |
| | $ | 794,020 |
| | $ | (14,556 | ) | | $ | 2,497,133 |
|
| Net loss | — |
| | — |
| | — |
| | (160,843 | ) | | — |
| | (160,843 | ) |
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 767 |
| | 767 |
|
| Cash dividends, $ 0.10 per share | — |
| | — |
| | — |
| | (11,144 | ) | | — |
| | (11,144 | ) |
| Issuance of common stock under Employee Stock Purchase Plan | 186,665 |
| | 2 |
| | 2,621 |
| | — |
| | — |
| | 2,623 |
|
| Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings | 171,278 |
| | 1 |
| | (1,241 | ) | | — |
| | — |
| | (1,240 | ) |
| Stock-based compensation expense | 71,573 |
| | 1 |
| | 22,699 |
| | — |
| | — |
| | 22,700 |
|
Cumulative effect of accounting change (1) | — |
| | — |
| | 1,108 |
| | 43,624 |
| | — |
| | 44,732 |
|
| Other | — |
| | — |
| | (120 | ) | | — |
| | — |
| | (120 | ) |
| Balances, December 31, 2017 | 111,687,016 |
| | $ | 1,117 |
| | $ | 1,741,623 |
| | $ | 665,657 |
| | $ | (13,789 | ) | | $ | 2,394,608 |
|
| Net income | — |
| | — |
| | — |
| | 508,407 |
| | — |
| | 508,407 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 4,378 |
| | 4,378 |
|
| Cash dividends, $0.10 per share | — |
| | — |
| | — |
| | (11,191 | ) | | — |
| | (11,191 | ) |
| Issuance of common stock under Employee Stock Purchase Plan | 199,464 |
| | 2 |
| | 3,185 |
| | — |
| | — |
| | 3,187 |
|
| Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings | 291,745 |
| | 3 |
| | (2,978 | ) | | — |
| | — |
| | (2,975 | ) |
| Stock-based compensation expense | 63,741 |
| | — |
| | 23,908 |
| | — |
| | — |
| | 23,908 |
|
Cumulative effect of accounting change (1) | — |
| | — |
| | — |
| | 2,969 |
| | (2,969 | ) | | — |
|
| Balances, December 31, 2018 | 112,241,966 |
| | $ | 1,122 |
| | $ | 1,765,738 |
| | $ | 1,165,842 |
| | $ | (12,380 | ) | | $ | 2,920,322 |
|
| Net loss | — |
| | — |
| | — |
| | (187,001 | ) | | — |
| | (187,001 | ) |
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1,061 |
| | 1,061 |
|
| Cash dividends declared, $0.10 per share | — |
| | — |
| | — |
| | (11,254 | ) | | — |
| | (11,254 | ) |
| Issuance of common stock under Employee Stock Purchase Plan | 314,868 |
| | 3 |
| | 3,206 |
| | — |
| | — |
| | 3,209 |
|
| Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings | 334,399 |
| | 4 |
| | (1,665 | ) | | — |
| | — |
| | (1,661 | ) |
| Stock-based compensation expense | 96,719 |
| | 1 |
| | 24,317 |
| | — |
| | — |
| | 24,318 |
|
| Balances, December 31, 2019 | 112,987,952 |
| | $ | 1,130 |
| | $ | 1,791,596 |
| | $ | 967,587 |
| | $ | (11,319 | ) | | $ | 2,748,994 |
|
| |
(1) | Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policiesfor additional information. |
The accompanying notes are an integral part of these consolidated financial statements.
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Cash flows from operating activities: | | | | | | | | | | |
| Net income (loss) | $ | (757,744 | ) | | $ | (447,710 | ) | | $ | 666,051 |
| $ | (187,001 | ) | | $ | 508,407 |
| | $ | (160,843 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | | |
| Net gain on divestiture activity | (37,074 | ) | | (43,031 | ) | | (646 | ) | |
| Net (gain) loss on divestiture activity | | (862 | ) | | (426,917 | ) | | 131,028 |
|
| Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 790,745 |
| | 921,009 |
| | 767,532 |
| 823,798 |
| | 665,313 |
| | 557,036 |
|
| Exploratory dry hole expense | (16 | ) | | 36,612 |
| | 44,427 |
| |
| Impairment of proved properties | 354,614 |
| | 468,679 |
| | 84,480 |
| |
| Abandonment and impairment of unproved properties | 80,367 |
| | 78,643 |
| | 75,638 |
| |
| Impairment of other property and equipment | — |
| | 49,369 |
| | — |
| |
| Impairment of oil and gas properties | | 33,842 |
| | 49,889 |
| | 16,078 |
|
| Stock-based compensation expense | 26,897 |
| | 27,467 |
| | 32,694 |
| 24,318 |
| | 23,908 |
| | 22,700 |
|
| Change in Net Profits Plan liability | (7,200 | ) | | (19,525 | ) | | (29,849 | ) | |
| Net derivative (gain) loss | 250,633 |
| | (408,831 | ) | | (583,264 | ) | 97,539 |
| | (161,832 | ) | | 26,414 |
|
| Derivative settlement gain | 329,478 |
| | 512,566 |
| | 12,615 |
| |
| Amortization of discount and deferred financing costs | 9,938 |
| | 7,710 |
| | 6,146 |
| |
| Non-cash (gain) loss on extinguishment of debt | (15,722 | ) | | 4,123 |
| | — |
| |
| Derivative settlement gain (loss) | | 39,222 |
| | (135,803 | ) | | 21,234 |
|
| Amortization of debt discount and deferred financing costs | | 15,474 |
| | 15,258 |
| | 16,276 |
|
| Loss on extinguishment of debt | | — |
| | 26,740 |
| | 35 |
|
| Deferred income taxes | (448,643 | ) | | (276,722 | ) | | 397,780 |
| (41,835 | ) | | 141,708 |
| | (192,066 | ) |
| Plugging and abandonment | (6,214 | ) | | (7,496 | ) | | (8,796 | ) | |
| Other, net | 3,499 |
| | 13,761 |
| | 1,069 |
| 2,220 |
| | 287 |
| | 7,885 |
|
| Changes in current assets and liabilities: | | | | | | | | | | |
| Accounts receivable | (10,562 | ) | | 140,200 |
| | 24,088 |
| (39,556 | ) | | (20,775 | ) | | 20,410 |
|
| Prepaid expenses and other | 8,478 |
| | 2,563 |
| | (1,822 | ) | 6,130 |
| | (729 | ) | | (1,953 | ) |
| Accounts payable and accrued expenses | (53,210 | ) | | (86,267 | ) | | 9,466 |
| 50,278 |
| | 35,175 |
| | 51,156 |
|
| Accrued derivative settlements | 34,540 |
| | 5,232 |
| | (41,034 | ) | |
| Net cash provided by operating activities | 552,804 |
| | 978,352 |
| | 1,456,575 |
| 823,567 |
| | 720,629 |
| | 515,390 |
|
| | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | |
| Net proceeds from the sale of oil and gas properties | 946,062 |
| | 357,938 |
| | 43,858 |
| 13,059 |
| | 748,509 |
| | 776,719 |
|
| Capital expenditures | (629,911 | ) | | (1,493,608 | ) | | (1,974,798 | ) | (1,023,769 | ) | | (1,303,188 | ) | | (888,353 | ) |
| Acquisition of proved and unproved oil and gas properties | (2,183,790 | ) | | (7,984 | ) | | (544,553 | ) | (2,581 | ) | | (33,255 | ) | | (89,896 | ) |
| Other, net | (3,000 | ) | | (985 | ) | | (3,256 | ) | |
| Net cash used in investing activities | (1,870,639 | ) | | (1,144,639 | ) | | (2,478,749 | ) | (1,013,291 | ) | | (587,934 | ) | | (201,530 | ) |
| | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | |
| Proceeds from credit facility | 947,000 |
| | 1,872,500 |
| | 1,285,500 |
| 1,589,000 |
| | — |
| | 406,000 |
|
| Repayment of credit facility | (1,149,000 | ) | | (1,836,500 | ) | | (1,119,500 | ) | (1,466,500 | ) | | — |
| | (406,000 | ) |
| Debt issuance costs related to credit facility | (3,132 | ) | | — |
| | (3,388 | ) | |
| Net proceeds from Senior Notes | 491,640 |
| | 490,951 |
| | 589,991 |
| — |
| | 492,079 |
| | — |
|
| Cash paid to repurchase Senior Notes | (29,904 | ) | | (350,000 | ) | | — |
| |
| Net proceeds from Senior Convertible Notes | 166,617 |
| | — |
| | — |
| |
| Cash paid for capped call transactions | (24,195 | ) | | — |
| | — |
| |
| Cash paid to repurchase Senior Notes, including premium | | — |
| | (845,002 | ) | | (2,357 | ) |
| Net proceeds from sale of common stock | 938,268 |
| | 4,844 |
| | 4,877 |
| 3,209 |
| | 3,187 |
| | 2,623 |
|
| Dividends paid | (7,751 | ) | | (6,772 | ) | | (6,723 | ) | (11,254 | ) | | (11,191 | ) | | (11,144 | ) |
| Net share settlement from issuance of stock awards | (2,354 | ) | | (8,678 | ) | | (10,624 | ) | |
| Other, net | — |
| | (160 | ) | | (87 | ) | (2,686 | ) | | (7,746 | ) | | (1,411 | ) |
| Net cash provided by financing activities | 1,327,189 |
| | 166,185 |
| | 740,046 |
| |
| Net cash provided by (used in) financing activities | | 111,769 |
| | (368,673 | ) | | (12,289 | ) |
| Net change in cash, cash equivalents, and restricted cash | | (77,955 | ) | | (235,978 | ) | | 301,571 |
|
| Cash, cash equivalents, and restricted cash at beginning of period | | 77,965 |
| | 313,943 |
| | 12,372 |
|
| Cash, cash equivalents, and restricted cash at end of period | | $ | 10 |
| | $ | 77,965 |
| | $ | 313,943 |
|
| | | | | | | | | | | |
| Net change in cash and cash equivalents | 9,354 |
| | (102 | ) | | (282,128 | ) | |
| Cash and cash equivalents at beginning of period | 18 |
| | 120 |
| | 282,248 |
| |
| Cash and cash equivalents at end of period | $ | 9,372 |
| | $ | 18 |
| | $ | 120 |
| |
| Supplemental schedule of additional cash flow information and non-cash activities: | | | | | | |
| Operating activities: | | | | | | |
| Cash paid for interest, net of capitalized interest | | $ | (141,902 | ) | | $ | (150,727 | ) | | $ | (164,097 | ) |
| Net cash (paid) refunded for income taxes | | $ | 6,109 |
| | $ | (2,995 | ) | | $ | (5,986 | ) |
| Investing activities: | | | | | | |
| Changes in capital expenditure accruals and other | | $ | (24,289 | ) | | $ | (2,774 | ) | | $ | 7,309 |
|
| Supplemental non-cash investing activities: | | | | | | |
| Carrying value of properties exchanged | | $ | 73,442 |
| | $ | 95,121 |
| | $ | 293,963 |
|
| Supplemental non-cash financing activities: | | | | | | |
| Non-cash loss on extinguishment of debt, net | | $ | — |
| | $ | 6,334 |
| | $ | 22 |
|
The accompanying notes are an integral part of these consolidated financial statements.
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Supplemental schedule of additional cash flow information and non-cash activities:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Supplemental Cash Flow Information: | | | | | |
| Operating activities: | | | | | |
| Cash paid for interest, net of capitalized interest | $ | 129,761 |
| | $ | 126,988 |
| | $ | 89,145 |
|
| Net cash (refunded) paid for income taxes | $ | (4,690 | ) | | $ | 1,630 |
| | $ | 1,936 |
|
| Investing activities: | | | | | |
| Changes in capital expenditure accruals and other | $ | 8,044 |
| | $ | (210,819 | ) | | $ | 130,143 |
|
| | | | | | |
| Supplemental Non-Cash Investing Activities: | | | | | |
| Fair value of properties exchanged | $ | 733 |
| | $ | — |
| | $ | 6,164 |
|
| | | | | | |
| Supplemental Non-Cash Financing Activities: | | | | | |
Issuance of common stock for an asset acquisition (1) | $ | 437,194 |
| | $ | — |
| | $ | — |
|
| |
(1)
| Refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale and Note 15 - Equity for additional discussion.
|
SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Summary of Significant Accounting Policies
Description of Operations
SM Energy Company, together with its consolidated subsidiaries, is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, and condensate, natural gas, and NGLs in onshore North America.
the state of Texas.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated events subsequent events afterto the balance sheet date of December 31, 2016,2019, through the filing date of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the consolidated financial statements.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.
Cash and Cash Equivalents
The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
Accounts Receivable
The Company’s accounts receivable consistconsists mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company typicallygenerally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil, gas, and gasNGL receivables are collected within two months30 to 90 days and the Company has had minimal bad debts.
Although diversified among many companies, collectabilitycollectibility is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. The Company’s allowance Please refer to Note 13 – Accounts Receivable and Accounts Payable and Accrued Expensesfor doubtful accounts as of December 31, 2016, and 2015, totaled $1.7 million and $1.1 million, respectively, primarily for receivables from joint interest owners.additional disclosure.
Concentration of Credit Risk and Major Customers
The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review.
The Company does not believe the loss of any single purchaser of its production would materially impact its operating results, as crude oil, natural gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating regions. The Company had the following major customercustomers and sales to entities under common ownership, whichcontrol accounted for 10 percent or more of its total oil, natural gas, and NGL production revenue for at least one of the periods presented:
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
Major customer (1) | 18 | % | | 21 | % | | 19 | % |
Group #1 of entities under common ownership (2) | 15 | % | | 10 | % | | 14 | % |
Group #2 of entities under common ownership (2) | 8 | % | | 11 | % | | 9 | % |
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
Major customer #1 (1) | 18 | % | | 18 | % | | 6 | % |
Major customer #2 (1) | 14 | % | | 5 | % | | 1 | % |
Major customer #3 (1) | 13 | % | | 7 | % | | — | % |
Major customer #4 (1) | 9 | % | | 10 | % | | 10 | % |
Group #1 of entities under common control (2) | 13 | % | | 18 | % | | 17 | % |
Group #2 of entities under common control (2) | 11 | % | | 12 | % | | 8 | % |
| |
(1) | ThisThese major customer is the operatorcustomers are purchasers of the Company’s outside-operated Eagle Ford shale program, in which the Company entered into various marketing agreements with during 2013, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because the Company shares with its operator the risk of non-performance by its counterparty purchasers, the Company has included its operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasersportion of the Company’s production from other areas. As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were classified as held for sale.its Midland Basin assets. |
| |
(2) | In the aggregate, these groups of entities under common ownership representcontrol represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for the period(s) shown, however, noneat least one of the entitiesperiods presented; however, 0 individual entity comprising either group individually representedwas a purchaser of more than 10 percent of the Company’s total oil, gas, and NGL production revenue. |
The Company’s policy is to useCompany generally contracts with the commodity affiliates of the lenders under its Credit Agreement as its derivative counterparties, and the Company’s policy is that each counterparty must have investment grade senior unsecured debt ratings. Each of the Company’s 10 derivative counterparties meet both of these requirements as of the filing date of this report.
The Company maintains its primary bank accounts with a large, multinational bank that has accountsbranch locations in the following locations with a national bank: Denver, Colorado; Houston, Texas; Midland, Texas; and Billings, Montana.Company’s areas of operations. The Company’s policy is to invest in highly-rated instrumentsdiversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure at each individual institution.to any single institution or investment. The Company maintains investments in highly rated, highly liquid investment products with numerous banks that are party to its revolving credit facility.
Oil and Gas Producing Activities
Proved properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, the costs of development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, and intangible development costs, and operational support facilities in the field, are depleted ason a group of assetsbasis (properties aggregated with a commonbased on geographical and geological structure)characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, producingproved leasehold costs are depleted on the same group asset basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.
Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that theassociated carrying costs may not be recoverable. ExpectedThe Company uses an income valuation technique, which converts future discounted cash flows are calculated on allflow to a single present value amount, to measure the fair value of proved reserves and risk adjusted probable and possible reserves usingproperties through an application of discount rates and price forecasts, as selected by the Company’s management. The Company uses discount rates that management believes are representative of current market conditions.conditions and considers estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The discount rates typically range from 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Please refer to Note 11 – Fair Value Measurements for additional discussion.
The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying consolidated statements of operations (“accompanying statements of operations”) for all other sales of proved properties.
Unproved properties. UnprovedThe unproved oil and gas properties consistline item on the accompanying balance sheets consists of costs incurred to acquire undevelopedunproved leases. Leasehold costs allocated to those leases, as well as acquisitions of unproved reserves. When successful wells are drilled on undeveloped leaseholds, unproved property costsor partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on a units-of-production basis. AnUnproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is recordedan indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved property whenproperties, the Company determines that eitheruses a market approach, which takes into account the property will not be developedfollowing significant
assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or the carrying value is not realizable. Please refer to Note 11 – Fair Value Measurements for additional discussion.other market participants.
The partialFor the sale of unproved property is accounted for asproperties where the original cost has been partially or fully amortized by providing a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A netvaluation allowance on a group basis, neither a gain on divestiture activitynor loss is recognized to the extent thatunless the sales price exceeds the carrying amountoriginal cost of the unproved property. A netproperty, in which case a gain or loss on divestiture activity isshall be recognized in the accompanying statements of operations for all other salesin the amount of unproved property.such excess.
Exploratory. G&G,Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory wells costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying consolidated statements of cash flows.
Other Property and Equipment
Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three3 to 30 years, or the unit of output method wherewhen appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.
A long-lived asset isOther property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. TheTo measure the fair value of other property and equipment, the Company uses an income valuation technique if there is not a market-observable price foror market approach depending on the asset. Please referquality of information available to Note 11 - Fair Value Measurements for additional discussion.
Assets Held for Sale
Any properties held for sale assupport management’s assumptions and the circumstances. The valuation includes consideration of the balance sheet date have been classified asproved and unproved assets held for salesupported by the property and are separately presented onequipment, future cash flows associated with the accompanying consolidated balance sheets (“accompanying balance sheets”) atassets, and fixed costs necessary to operate and maintain the lower of carrying value or fair value less the cost to sell. Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale and Note 11 - Fair Value Measurements for additional discussion.assets.
Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, andor a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the Company’s accompanying consolidated statements of cash flows.
The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, or changes in inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 914 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2016,2019, and 2015.2018.
Derivative Financial Instruments
The Company seeksperiodically enters into commodity derivative instruments to manage or reducemitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price risk on its production by entering intoswaps and costless collars, as well as, basis differential swaps. Commodity derivative contracts. The Company seeks to minimize its basis riskinstruments are measured at fair value and indexes its oilare included in the accompanying balance sheets as derivative contracts to NYMEX prices, its NGLassets and liabilities, with the exception of derivative contracts to OPIS prices, and its gas derivative contracts to various regional index prices associated with pipelines into whichinstruments that meet the Company’s gas production is sold.“normal purchase normal sale” exclusion. The Company does not designate its derivative instruments to qualify for hedge accounting.commodity contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on derivatives
are included within the cash flows from operating activities section of the accompanying statements of cash flows. For additional discussion on derivatives, please see refer to Note 10 – Derivative Financial Instruments.
Revenue Recognition
The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and title (“control”) of the Company’s production is deliveredproduct transfers to the purchaser, but payment is generally received between 30which may differ depending on the applicable contractual terms. Revenue accruals are recorded monthly and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount ofare based on estimated production delivered to thea purchaser and the expected price to be received. Variances between estimates and the Company will receive. The Company uses knowledge of its properties and historical performance, contractual agreements, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors asactual amounts received are recorded in the basismonth payment is received. Please refer to Note 2 - Revenue from Contracts with Customers for these estimates. The Company follows the sales method of accounting for natural gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance.additional discussion.
Stock-Based Compensation
At December 31, 2016,2019, the Company had stock-based employee compensation plans that included RSUsrestricted stock units (“RSUs”) and PSUsperformance share units (“PSUs”) issued to employees, RSUs and restricted stock issued to non-employee directors, as well asand an employee stock purchase plan available to eligible employees. These are more fully described in Note 7 -– Compensation Plans. Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative expense and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur.
Income Taxes
The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis.
Please refer to Note 4 – Income Taxesfor additional disclosure.
Earnings per Share
Basic net income (loss) per common share is calculated by dividing net income or loss availableThe Company uses the treasury stock method to common stockholders bydetermine the basic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.
Diluted net income (loss) per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes thepotential dilutive effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvestednon-vested RSUs, contingent PSUs, shares issuable upon the conversion of theand Senior Convertible Notes, and in-the-money outstanding stock options, which are measured using the treasury stock method. All outstanding stock options were exercised during the year ended December 31, 2014. When the Company recognizes a loss from continuing operations, as was the case for the years ended December 31, 2016, and 2015, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share.
PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units.
On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which allows the Company to settle the principal amount of the Senior Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. However, the Company reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business conditions warrant. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the portion of the year ended December 31, 2016, during which the Senior Convertible Notes were outstanding. In connection with the Senior Convertible Notes offering, the Company entered into capped call transactions with affiliates of the underwriters that effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions are not reflected in diluted net income per share, nor will they ever be, as they are anti-dilutive.Notes. Please refer to Note 59 - Long-Term DebtEarnings Per Share for additional discussion.
The following table details the weighted-average dilutive and anti-dilutive securities for the years presented:
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Dilutive | — |
| | — |
| | 814 |
|
| Anti-dilutive | 280 |
| | 256 |
| | — |
|
The following table sets forth the calculations of basic and diluted earnings per share:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands, except per share amounts) |
| Net income (loss) | $ | (757,744 | ) | | $ | (447,710 | ) | | $ | 666,051 |
|
| Basic weighted-average common shares outstanding | 76,568 |
| | 67,723 |
| | 67,230 |
|
Add: dilutive effect of unvested RSUs, contingent PSUs, and stock options (1) | — |
| | — |
| | 814 |
|
Add: dilutive effect of 1.50% Senior Convertible Notes (2) | — |
| | — |
| | — |
|
| Diluted weighted-average common shares outstanding | 76,568 |
| | 67,723 |
| | 68,044 |
|
| Basic net income (loss) per common share | $ | (9.90 | ) | | $ | (6.61 | ) | | $ | 9.91 |
|
| Diluted net income (loss) per common share | $ | (9.90 | ) | | $ | (6.61 | ) | | $ | 9.79 |
|
| |
(1)
| For the years ended December 31, 2016, and 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share. |
| |
(2)
| For the year ended December 31, 2016, shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price, and therefore, had no dilutive impact and were excluded from the calculation of diluted earnings per share. |
Comprehensive Income (Loss)
Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss) (“accompanying statements of comprehensive income (loss)”).
The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. Please refer to Note 8 – Pension Benefits for detail on the changes in the balances of components comprising other comprehensive income (loss) are presented in the following table:
|
| | | |
| | Pension Liability Adjustments |
| | (in thousands) |
| For the year ended December 31, 2014 | |
| Net actuarial loss | $ | (10,062 | ) |
| Reclassification to earnings | 706 |
|
| Tax benefit | 3,460 |
|
| Loss, net of tax | $ | (5,896 | ) |
| For the year ended December 31, 2015 | |
| Net actuarial loss | $ | (4,990 | ) |
| Reclassification to earnings | 1,853 |
|
| Tax benefit | 1,047 |
|
| Loss, net of tax | $ | (2,090 | ) |
| For the year ended December 31, 2016 | |
| Net actuarial loss | $ | (3,322 | ) |
| Reclassification to earnings | 1,598 |
|
| Tax benefit | 570 |
|
| Loss, net of tax | $ | (1,154 | ) |
.
Fair Value of Financial Instruments
The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had a zero$122.5 million balance under its credit facility as of December 31, 2016,2019, compared with $202.0 million of outstanding loansa 0 balance as of December 31, 2015.2018. The Company’s Senior Notes and Senior Convertible Notes are recorded at cost, net of any unamortized discount and deferred financing costs, and thetheir respective fair values are disclosed in Note 11 -– Fair Value Measurements. TheMeasurements. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.
Industry Segment and Geographic Information
The Company operates in the exploration and production segment of the oil and gas industry, withinonshore in the United States. The Company reports as a single industry segment. Prior to the sale of the Company’s Mid-Continent assets in 2015, the Company acted as the first purchaser of natural gas and natural gas liquids produced by third parties in certain cases. The Company considered this function as ancillary to its oil and gas producing activities. The amount of income these operations generated from marketing gas produced by third parties was not material to the Company’s results of operations, and segmentation of such activity would not have provided a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties is presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations. There was no marketed gas system revenue or expense recorded for the year ended December 31, 2016.
Off-Balance Sheet Arrangements
The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”),SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.
The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated. The Company has not been involved in any unconsolidated SPE transactions in 20162019 or 2015.2018.
Recently Issued Accounting Standards
Effective January 1, 2016,2017, the Company adopted, on a retrospective basis,using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-02, Consolidation2016-09, Compensation-Stock Compensation (Topic 810)718): Amendments to the Consolidation Analysis. This ASU clarifies the consolidation reporting guidance in GAAP. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard.
Effective December 31, 2016, the Company adopted FASB ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This ASU requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) for the recognition of revenue from contracts with customers. Subsequent to the issuance of this ASU, the FASB issued additional related ASUs as follows:
In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. This ASU deferred the effective date of ASU 2014-09 by one year.
In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09.
In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09.
In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. This ASU amends certain issues in ASU 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes.
In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with CustomersEmployee Share-Based Payment Accounting (“ASU 2016-09”). This ASU 2016-09 is meant to improve and clarify or to correct unintended application of narrowsimplify certain aspects of accounting for share-based arrangements, including income tax effects, accounting for forfeitures, and net share settlements. The Company adopted the guidance in ASU 2014-09.
various applicable amendments, which are summarized as follows:
ASU 2014-09On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and each update have the same effective date and transition requirements. That is, the guidance under these standards is to be applieda corresponding deferred tax asset was recorded for previously unrecognized excess tax benefits using a full retrospective method or a modified retrospective method, as outlinedtransition method. Effective January 1, 2017, excess tax benefits are presented in ASU 2014-09, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company has established a cross-functional implementation team that is currently evaluating the provisions of each of these standards, analyzing their impactnet cash provided by operating activities on the Company’s contract portfolio, reviewing current accounting policiesaccompanying statements of cash flows.
On January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and practicesresulted in an increase in additional paid-in capital of $1.1 million, a decrease in deferred tax assets of $400,000, and a net $700,000 cumulative effect decrease to identify potential differences that would resultretained earnings.
Under this new guidance, excess tax benefits and deficiencies from applying the requirements of these standards toshare-based payments impact the Company’s revenue contracts, and assessing their potential impact on the Company’s financial statements and disclosures. The Company currently plans to apply the modified retrospective method upon adoption and plans to adopt the guidance on the effective date of January 1, 2018.tax rate between periods.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which changesfollowed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby lease accounting for previously reported periods continues to be reported in accordance with historical accounting guidance for leases in effect for those prior periods. Policy elections and practical expedients the Company implemented in connection with the adoption of ASU 2016-02 include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources.
Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. ThisThere was no cumulative effect adjustment to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leasesfor additional discussion.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for annual periods, and interim periods within those annual periods,fiscal years beginning after December 15, 2018. Early2019, with early adoption is permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 is currently evaluating the provisions of this guidance and assessing its potentialnot expected to result in a material impact onto the Company’s consolidated financial statements andor disclosures.
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU makes targeted amendments to the accounting for employee share-based payments. This guidance is to be applied using various transition methods, such as full retrospective, modified retrospective, and prospective, based on the criteria for the specific amendments as outlined in the guidance. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted, as long as all of the amendments are adopted in the same period; however, the Company plans on adopting in the first quarter of 2017. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. This guidance is to be applied using a retrospective method. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, as long as all of the amendments are adopted in the same period. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU clarifies how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations2017-07, Compensation-Retirement Benefits (Topic 805)715): ClarifyingImproving the DefinitionPresentation of a Business Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-01”2017-07”). This ASU clarifies2017-07 requires presentation of service cost in the definitionsame line item(s) as other compensation costs arising from services rendered by employees during the period, and presentation of the remaining components of net benefit cost in a businessseparate line item, outside operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company adopted ASU 2017-07 on the effective date of January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost in the consolidated statements of operations, and prospective application for the capitalization of the service cost component of net benefit costs in assets. While the adoption of ASU 2017-07 resulted in the Company reclassifying certain amounts from operating expenses to non-operating expenses, ASU 2017-07 did not result in a material impact to the Company’s consolidated financial statements or disclosures.
In February 2018, the FASB issued ASU No. 2018-02, Income Statement–Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”). ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the 2017 Tax Act. The Company early adopted ASU 2018-02 effective January 1, 2018 using a retrospective method. As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the objectiverequirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company adopted ASU 2018-15 on January 1, 2020, with prospective application. The adoption of adding guidanceASU 2018-15 is not expected to assisthave a material impact to the Company’s consolidated financial statements or disclosures.
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). ASU 2019-12 was issued as a means to reduce the complexity of accounting for income taxes for those entities with evaluating whether transactions should be accounted for as acquisitions (or disposals)that fall within the scope of assets or businesses. Thisthe accounting standard. The guidance is to be applied using a prospective method, andexcluding amendments related to franchise taxes, which should be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. ASU 2019-12 is effective for annual periods, and interim periods within those annual periods,fiscal years beginning after December 15, 2017. Early2020, with early adoption is permitted as outlined in ASU 2017-01.permitted. The Company is currently evaluating the provisionsimpact of this guidance and assessingASU 2019-12 on its potential impact on the Company’sconsolidated financial statements and disclosures.
In February 2017, the FASB issued ASU No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This ASU is meant to clarify the scope of ASC Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partial sales of nonfinancial assets. This guidance is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the same time as ASU 2014-09. Further, the Company is required to adopt this guidance at the same time that it adopts the guidance in ASU 2014-09. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures.
statements.
There are no other accounting standardsASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of December 31, 2016,2019, and through the filing date of this report.
Note 2 – Accounts Receivable- Revenue from Contracts with Customers
The Company recognizes its share of revenue from the sale of produced oil, gas, and Accounts PayableNGLs in its Midland Basin and Accrued Expenses
Accounts receivable are comprisedSouth Texas assets. Following the divestiture of the following:
|
| | | | | | | |
| | As of December 31, |
| | 2016 |
| 2015 |
| | (in thousands) |
| Accrued oil, gas, and NGL production revenue | $ | 96,101 |
| | $ | 58,256 |
|
| Amounts due from joint interest owners | 29,669 |
| | 22,269 |
|
| State severance tax refunds | 15,320 |
| | 12,072 |
|
| Accrued derivative settlements | 6,512 |
| | 34,579 |
|
| Other | 4,348 |
| | 6,948 |
|
| Total accounts receivable | $ | 151,950 |
| | $ | 134,124 |
|
Accounts payableCompany’s remaining assets in the Rocky Mountain region during the first half of 2018, there has been no production revenue from this region after the second quarter of 2018. Oil, gas, and accrued expenses are comprisedNGL production revenue presented within the accompanying statements of operations is reflective of the following:revenue generated from contracts with customers.
The tables below present the oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the years ended December 31, 2019, 2018, and 2017: |
| | | | | | | | | | | |
| | For the year ended December 31, 2019 |
| | Midland Basin | | South Texas | | Total |
| | (in thousands) |
| Oil production revenue | $ | 1,119,786 |
| | $ | 63,426 |
| | $ | 1,183,212 |
|
| Gas production revenue | 75,827 |
| | 186,702 |
| | 262,529 |
|
| NGL production revenue | 123 |
| | 139,886 |
| | 140,009 |
|
| Total | $ | 1,195,736 |
| | $ | 390,014 |
| | $ | 1,585,750 |
|
| Relative percentage | 75 | % | | 25 | % | | 100 | % |
|
| | | | | | | |
| | As of December 31, |
| | 2016 | | 2015 |
| | (in thousands) |
| Accrued capital expenditures | $ | 107,009 |
| | $ | 97,355 |
|
| Revenue and severance tax payable | 39,617 |
| | 44,387 |
|
| Accrued lease operating expense | 15,956 |
| | 21,943 |
|
| Accrued property taxes | 6,606 |
| | 14,078 |
|
| Accrued compensation | 34,761 |
| | 41,154 |
|
| Accrued derivative settlements | 6,473 |
| | — |
|
| Accrued interest | 45,059 |
| | 34,378 |
|
| Other | 44,227 |
| | 49,222 |
|
| Total accounts payable and accrued expenses | $ | 299,708 |
| | $ | 302,517 |
|
|
| | | | | | | | | | | | | | | |
| | For the year ended December 31, 2018 |
| | Midland Basin | | South Texas | | Rocky Mountain | | Total |
| | (in thousands) |
| Oil production revenue | $ | 938,004 |
| | $ | 72,821 |
| | $ | 54,851 |
| | $ | 1,065,676 |
|
| Gas production revenue | 125,603 |
| | 227,252 |
| | 1,595 |
| | 354,450 |
|
| NGL production revenue | 1,000 |
| | 214,441 |
| | 790 |
| | 216,231 |
|
| Total | $ | 1,064,607 |
| | $ | 514,514 |
| | $ | 57,236 |
| | $ | 1,636,357 |
|
| Relative percentage | 65 | % | | 32 | % | | 3 | % | | 100 | % |
Note: Amounts may not calculate due to rounding.
|
| | | | | | | | | | | | | | | |
| | For the year ended December 31, 2017 |
| | Midland Basin | | South Texas | | Rocky Mountain | | Total |
| | (in thousands) |
| Oil production revenue | $ | 419,732 |
| | $ | 82,674 |
| | $ | 151,844 |
| | $ | 654,250 |
|
| Gas production revenue | 61,781 |
| | 301,780 |
| | 5,849 |
| | 369,410 |
|
| NGL production revenue | 547 |
| | 226,031 |
| | 3,545 |
| | 230,123 |
|
| Total | $ | 482,060 |
| | $ | 610,485 |
| | $ | 161,238 |
| | $ | 1,253,783 |
|
| Relative percentage | 38 | % | | 49 | % | | 13 | % | | 100 | % |
Note: Amounts may not calculate due to rounding.
The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the purchaser, which differs depending on the applicable contractual terms. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred by the Company prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred at or near the wellhead, sales are based on a wellhead market price that is impacted by fees and other deductions incurred by the purchaser subsequent to the transfer of control. In general, the Company generates production revenue from a combination of the following types of contracts:
The Company sells oil and gas production at or near the wellhead and receives an agreed-upon market price from the purchaser. Under this type of arrangement, control transfers at or near the wellhead.
The Company has certain processing arrangements that include the delivery of unprocessed gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company based on the proceeds the processor realizes from selling the NGLs to third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.
Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers, relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.
The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are 0 material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.
Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of December 31, 2019, and 2018, were $146.3 million and $107.2 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser.
Note 3 – Acquisitions, Divestitures, and Assets Held for Sale, and Acquisitions
2016 Acquisition2019 Divestiture Activity
No material divestitures occurred during 2019.
2018 Divestiture Activity
Rock Oil Acquisition. PRB Divestiture. On October 4, 2016, March 26, 2018,the Company acquired all membership interestscompleted the PRB Divestiture, divesting of JPM EOC Opal, LLC, which owned proved and unproved properties in the Midland Basin, from Rock Oil Holdings, LLCapproximately 112,000 net acres for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $492.2 million, and recorded a final net gain of $410.6 million for the “Rock Oil Acquisition”)year ended December 31, 2018.
Divide County Divestiture and Halff East Divestiture. During the second quarter of 2018, the Company completed the Divide County Divestiture and the Halff East Divestiture, for an adjusted purchase pricecombined net divestiture proceeds of $991.0$252.2 million, and recorded a combined final net gain of $15.4 million for the year ended December 31, 2018.
The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the years ended December 31, 2019, 2018, and 2017. The Divide County Divestiture was considered a disposal of a significant asset group. |
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands) |
Loss before income taxes (1) | $ | — |
| | $ | (28,975 | ) | | $ | (468,786 | ) |
| |
(1) | Loss before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity. During the year ended December 31, 2017, the Company recorded a write-down of $523.6 million on these assets. |
2017 Divestiture Activity
Eagle Ford Divestiture. On March 10, 2017,the Company divested its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets, for final net divestiture proceeds of $744.1 million. The effective dateCompany recorded a final net gain of $396.8 million related to these divested assets for the acquisitionyear ended December 31, 2017. This divestiture was September 1, 2016. Theconsidered a disposal of a significant asset group. For the year ended December 31, 2017, income before income taxes from the outside-operated Eagle Ford shale assets sold was $24.3 million. This amount reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion expense.
During 2017, the Company funded the acquisition withdivested certain non-core properties for net divestiture proceeds from divestitures in 2016of $36.2 million and the Senior Convertible Notes and equity offerings in August 2016, as discussed in Note 5 - Long-Term Debt and Note 15 - Equity,respectively.
recognized an insignificant final net gain.
The Company determined that executed asset sales in 2018 and 2017 did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.
2019 Acquisition Activity
During 2019, the Rock Oil Acquisition metCompany completed several non-monetary acreage trades of primarily undeveloped properties located in Howard, Martin, and Midland Counties, Texas, resulting in the criteriaexchange of a business combination under ASC Topic 805, Business Combinations. The Company allocated the preliminary adjusted purchase priceapproximately 2,200 net acres, with $73.4 million of carrying value attributed to the acquired assets and liabilities based on fair value as ofproperties transferred by the acquisition date, as summarized in the table below. This measurement resulted in no goodwillCompany. These trades were recorded at carryover basis with 0 gain or bargain purchase gain beingloss recognized. Refer to Note 11 - Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair value of the acquired properties. The acquisition costs were insignificant and were expensed as incurred.
|
| | | |
| | As of October 4, 2016 |
| | (in thousands) |
| Cash consideration | $ | 991,038 |
|
| | |
| Fair value of assets and liabilities acquired: | |
| Wells in progress | $ | 5,672 |
|
| Proved oil and gas properties | 81,917 |
|
| Unproved oil and gas properties | 913,594 |
|
| Other assets | 5,338 |
|
| Total fair value of oil and gas properties acquired | 1,006,521 |
|
| Working capital | (7,888 | ) |
| Asset retirement obligation | (7,595 | ) |
| Total fair value of net assets acquired | $ | 991,038 |
|
2018 Acquisition Activity
QStar Acquisition. OnDuring the year ended December 21, 2016,31, 2018, the Company acquired additional proved andapproximately 1,030 net acres of primarily unproved properties located in the Midland Basin from QStar LLCMartin and RRP-QStar, LLC (referred to as the “QStar Acquisition”) for $1.6 billion, consisting of $1.2 billionHoward Counties, Texas, in two separate transactions which closed in 2018. Combined total cash consideration andpaid by the issuance of approximately 13.4 million shares of the Company’s common stock. The cash considerationCompany was funded by proceeds from the recent Raven/Bear Den divestiture and the December 2016 equity offering. Please refer to Note 15 - Equity for additional discussion. The effective date of the acquisition was September 1, 2016.$33.3 million. Under authoritative accounting guidance, the transaction wasthese transactions were both individually considered anto be asset acquisition, and therefore,acquisitions. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired.
TheDuring the third quarter of 2018, the Company allocatedcompleted two non-monetary acreage trades of primarily undeveloped properties located in Howard and Martin Counties, Texas, which resulted in the preliminary adjusted purchase priceexchange of approximately 2,650 net acres, with $95.1 million of carrying value attributed to the acquired assets and liabilities, as summarized inproperties transferred by the table below.Company. These trades were recorded at carryover basis with 0 gain or loss recognized.
2017 Acquisition Activity |
| | | |
| | As of December 21, 2016 |
| | (in thousands) |
| Cash consideration, including acquisition costs paid | $ | 1,167,373 |
|
Fair value of equity consideration (1) | 437,194 |
|
| Total consideration at closing | $ | 1,604,567 |
|
| | |
| Assets and liabilities acquired: | |
| Wells in progress | $ | 21,812 |
|
| Proved oil and gas properties | 61,614 |
|
| Unproved oil and gas properties | 1,537,923 |
|
| Total oil and gas properties acquired | 1,621,349 |
|
| Working capital | (9,141 | ) |
| Asset retirement obligation | (7,641 | ) |
| Total net assets acquired | $ | 1,604,567 |
|
| |
(1)
| The Company issued approximately 13.4 million shares of common stock, par value $0.01 per share, in a private placement to the sellers in the QStar Acquisition on December 21, 2016. The equity consideration was valued on this date using Level 1 and Level 2 inputs with a discount applied due to the lack of marketability in the near term in accordance with the Lock-Up and Registration Rights Agreement that prohibits the sale of such stock until no earlier than the 90th day after issuance. |
The Rock Oil Acquisition and QStar Acquisition are each subject to normal post-closing adjustments expected to occur inDuring the first half of 2017. These post-closing adjustments are estimated as ofyear ended December 31, 2016, and reflected in the tables above.
Other Acquisitions. During the fourth quarter of 2016,2017, the Company entered into a definitive purchase agreement to acquireacquired approximately 2,9003,600 net acres of oilprimarily unproved properties in Howard and gas assetsMartin Counties, Texas, in the Midland Basinmultiple transactions for a gross purchase pricetotal of $60$76.5 million subjectof cash consideration. Under authoritative accounting guidance, these transactions were individually considered to customary purchase price adjustments. Thisbe asset acquisitions. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition closed subsequent to December 31, 2016.
date and the transaction costs were capitalized as a component of the cost of the assets acquired.2015 Acquisition Activity
There was no significant acquisition activityAlso during the year ended December 31, 2015.
2014 Acquisition Activity
Gooseneck Property Acquisitions
On September 24, 2014,2017, the Company acquiredcompleted several non-monetary acreage trades of primarily unproved properties in Howard and Martin Counties, Texas, resulting in the exchange of approximately 61,0008,125 net acres for approximately 7,580 net acres with $294.0 million of proved and unproved oil and gascarrying value attributed to the properties in its Gooseneck area in North Dakota, along with related equipment, contracts, records, and other assets. Total cash consideration paidtransferred by the Company after final closing adjustments was $321.8 million and the effective date for the acquisition was July 1, 2014.
On October 15, 2014, the Company acquired additional interests in proved and unproved oil and gas properties in its Gooseneck area. Total cash consideration paid by the Company was $84.8 million and the effective date for the acquisition was August 1, 2014.
Each of these acquisitions qualified as a business combination under ASC Topic 805, Business Combinations. The Company allocated the final adjusted purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below.such trades. These measurements resulted in no goodwill or bargain purchase gain being recognized.
|
| | | | | | | |
| | Acquisition #1 | | Acquisition #2 |
| | As of September 24, 2014 | | As of October 15, 2014 |
| | (in thousands) |
| Cash consideration | $ | 321,807 |
| | $ | 84,836 |
|
| | | | |
| Fair value of assets and liabilities acquired: | | | |
| Proved oil and gas properties | $ | 203,467 |
| | $ | 54,612 |
|
| Unproved oil and gas properties | 126,588 |
| | 29,610 |
|
| Total fair value of oil and gas properties acquired | 330,055 |
| | 84,222 |
|
| Working capital | (6,135 | ) | | 2,232 |
|
| Asset retirement obligation | (2,113 | ) | | (1,618 | ) |
| Total fair value of net assets acquired | $ | 321,807 |
| | $ | 84,836 |
|
Rocky Mountain Acquisitions. In addition to the Gooseneck property acquisitions discussed above, the Company acquired other proved and unproved properties in its Rocky Mountain region during 2014, primarily in the Powder River Basin, in multiple transactions for approximately $135.5 million in total cash consideration after final closing adjustments, plus approximately 7,000 net acres of non-core assets in the Company’s Rocky Mountain region.
2016 Divestiture Activity
Rocky Mountain Divestitures. During the third quarter of 2016, the Company divested certain non-core properties in the Williston Basin and Powder River Basin in two separate packages for total cash receivedtrades were recorded at closing, net of commissions and payments to Net Profits Plan participants (referred throughout this report as “net divestiture proceeds”), of $110.6 million. The Company recorded a net gain of $16.4 million related to these divested assets for the year ended December 31, 2016.
During the fourth quarter of 2016, the Company divested certain Williston Basin assets located outside of Divide County, North Dakota (referred to as “Raven/Bear Den” throughout this report) for net divestiture proceeds of $756.2 million. The Company recorded a net gain of $29.5 million related to these divested assets for the year ended December 31, 2016. In conjunctioncarryover basis with the divestiture of certain Rocky Mountain assets, the Company closed its Billings, Montana office. Please refer to Note 14 - Exit and Disposal Costs for additional discussion.
The following table presents income (loss) before income taxes of the Raven/Bear Den assets sold on December 1, 2016, for the years ended December 31, 2016, 2015, and 2014. This divestiture is considered a disposal of a significant asset group.
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
Income (loss) before income taxes (1) | $ | (6,601 | ) | | $ | (12,530 | ) | | $ | 197,256 |
|
| |
(1)
| Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes includes impairment of proved properties expense of approximately $17.8 million for the year ended December 31, 2015. |
Permian Divestiture. During the third quarter of 2016, the Company divested its non-core properties in southeast New Mexico for net divestiture proceeds of $54.6 million and recorded a net loss of $10.1 million for the year ended December 31, 2016.
Each of these divestitures are subject to normal post-closing adjustments, and the respective post-closings are expected to occur in the first half of 2017.
2015 Divestiture Activity
Mid-Continent Divestiture. During the second quarter of 2015, the Company divested its Mid-Continent assets in multiple transactions for total net divestiture proceeds of $310.3 million and a final net gain of $108.4 million. In conjunction with the divestiture of its Mid-Continent assets, the Company closed its Tulsa, Oklahoma office. Please refer to Note 14 - Exit and Disposal Costs for additional discussion.
Permian Divestiture. During the fourth quarter of 2015, the Company divested certain non-core assets in its Permian region. Net divestiture proceeds were $25.1 million and the final net gain on this divestiture was $2.3 million.
Write-downs on certain other assets held for sale and subsequently sold during the year ended December 31, 2015, totaled $68.6 million, which partially offset the net gain on the Mid-Continent and Permian divestitures discussed above.
2014 Divestiture Activity
Rocky Mountain Divestiture. During the second quarter of 2014, the Company divested certain non-core assets in the Montana portion of the Williston Basin. Net divestiture proceeds were $42.0 million and the final net gain on this divestiture was $26.9 million.
The Company recorded $27.6 million of write-downs to fair value less estimated costs to sell for assets that were held for sale during the year ended December 31, 2014, which offset the net gain on the Rocky Mountain Divestiture discussed above.
Assets Held for Sale
Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Any subsequent changes to the fair value less estimated costs to sell impact the measurement of assets held for sale, with any0 gain or loss reflected in the net gain on divestiture activity line item in the accompanying statements of operations.recognized.
As of December 31, 2016, the accompanying balance sheets present $372.6 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consists of the Company’s outside-operated Eagle Ford shale assets. A corresponding aggregate asset retirement obligation liability of $26.2 million is separately presented. There were no material assets held for sale as of December 31, 2015.
Subsequent to December 31, 2016, the Company entered into a definitive agreement with Venado EF LLC (“Venado”) for the sale of its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets (the “Eagle Ford Transaction”) for a gross purchase price of $800 million, subject to customary purchase price adjustments. The Company expects to close the Eagle Ford Transaction in the first quarter of 2017.
Pursuant to the Venado definitive agreement, the Company entered into certain NYMEX swap contracts to be novated to Venado at closing, as summarized below:
Oil swap contracts through the fourth quarter of 2021 for a total of 4.3 million Bbls of oil production at contract prices ranging from $54.05 to $57.00 per Bbl.
Gas swap contracts through the fourth quarter of 2021 for a total of 4.6 million MMBtu of gas production at contract prices ranging from $2.82 to $2.99 per MMBtu.
NGL swap contracts through the fourth quarter of 2019 for a total of 4.5 million Bbls of NGL production at contract prices ranging from $11.81 to $48.51 per Bbl.
The Company is not at risk of a net financial obligation with the derivative counterparties should the value of the contracts become negative, unless the Eagle Ford Transaction is terminated because the Company did not comply in all material respects with its covenants under the definitive agreement or because of a material inaccuracy of the Company’s representations and warranties.
The closing of the Eagle Ford Transaction is subject to the satisfaction of customary closing conditions, and there can be no assurance that it will close on the expected closing date or at all.
The following table presents income (loss) before income taxes for the years ended December 31, 2016, 2015, and 2014, of the Company’s outside-operated Eagle Ford shale assets held for sale as of December 31, 2016, which is considered a significant asset disposal group.
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
Income (loss) before income taxes (1) | $ | (218,506 | ) | | $ | 71,556 |
| | $ | 294,376 |
|
| |
(1)
| Income (loss) before income taxes reflects oil, gas, and NGL production revenue less oil, gas, and NGL production expense and depletion, depreciation, amortization, and asset retirement obligation liability accretion expense. Additionally, loss before income taxes for the year ended December 31, 2016, includes $269.6 million of proved property impairment expense. |
Subsequent to December 31, 2016, the Company announced its plans to sell its remaining Williston Basin assets in the Divide County, North Dakota area (referred to as “Divide County” throughout this report) by mid-year 2017. These assets were classified as held and used as of December 31, 2016. Based on preliminary estimates of fair value less selling costs as of the filing date of this report, the Company expects to record a write down in the range of $200 million to $400 million in the first quarter of 2017 upon the Divide County assets being reclassified to held for sale.
The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accounting under financial statement presentation authoritative guidance.
Note 4 – Income Taxes
The provision for income taxes consists of the following:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands) |
| Current portion of income tax expense (benefit) | | | | | |
| Federal | $ | (3,826 | ) | | $ | — |
| | $ | 5,698 |
|
| State | 1,618 |
| | 1,662 |
| | 3,398 |
|
| Deferred portion of income tax expense (benefit) | (41,835 | ) | | 141,708 |
| | (192,066 | ) |
| Income tax expense (benefit) | $ | (44,043 | ) | | $ | 143,370 |
| | $ | (182,970 | ) |
| | | | | | |
| Effective tax rate | 19.1 | % | | 22.0 | % | | 53.2 | % |
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2016 | | 2015 | | 2014 |
| | | (in thousands) |
| Current portion of income tax expense | | | | | | |
| Federal | | $ | 2,932 |
| | $ | — |
| | $ | — |
|
| State | | 1,539 |
| | 1,571 |
| | 868 |
|
| Deferred portion of income tax expense (benefit) | | (448,643 | ) | | (276,722 | ) | | 397,780 |
|
| Total income tax expense (benefit) | | $ | (444,172 | ) | | $ | (275,151 | ) | | $ | 398,648 |
|
| Effective tax rate | | 37.0 | % | | 38.1 | % | | 37.4 | % |
The components of the net deferred income tax liabilities are as follows:
|
| | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Deferred tax liabilities | | | |
| Oil and gas properties | $ | 205,028 |
| | $ | 218,094 |
|
| Derivative assets | 4,646 |
| | 35,247 |
|
| Other | 12,361 |
| | 4,812 |
|
| Total deferred tax liabilities | 222,035 |
| | 258,153 |
|
| Deferred tax assets |
|
| |
|
|
| Credit carryover | 11,270 |
| | 22,554 |
|
| Pension | 5,971 |
| | 6,427 |
|
| Federal and state tax net operating loss carryovers | 4,172 |
| | 4,217 |
|
| Stock compensation | 3,503 |
| | 3,263 |
|
| Other liabilities | 10,803 |
| | 1,497 |
|
| Total deferred tax assets | 35,719 |
| | 37,958 |
|
| Valuation allowance | (3,070 | ) | | (3,083 | ) |
| Net deferred tax assets | 32,649 |
| | 34,875 |
|
| Total net deferred tax liabilities | $ | 189,386 |
| | $ | 223,278 |
|
| | | | |
| Current federal income tax refundable | $ | 3,885 |
| | $ | 59 |
|
| Current state income tax payable | $ | 1,404 |
| | $ | 1,331 |
|
|
| | | | | | | | |
| | | As of December 31, |
| | | 2016 | | 2015 |
| | | (in thousands) |
| Deferred tax liabilities: | | | | |
| Oil and gas properties | | $ | 518,394 |
| | $ | 854,029 |
|
| Derivative asset | | — |
| | 179,543 |
|
| Other | | 7,733 |
| | 1,233 |
|
| Total deferred tax liabilities | | 526,127 |
| | 1,034,805 |
|
| Deferred tax assets: | |
|
| |
|
|
| Federal and state tax net operating loss carryovers | | 151,343 |
| | 244,942 |
|
| Derivative liability | | 31,349 |
| | — |
|
| Stock compensation | | 10,083 |
| | 14,529 |
|
| Credit carryover | | 12,448 |
| | 6,952 |
|
| Other liabilities | | 10,567 |
| | 20,497 |
|
| Total deferred tax assets | | 215,790 |
| | 286,920 |
|
| Valuation allowance | | (5,335 | ) | | (10,394 | ) |
| Net deferred tax assets | | 210,455 |
| | 276,526 |
|
| Total net deferred tax liabilities | | $ | 315,672 |
| | $ | 758,279 |
|
| Current federal income tax refundable | | $ | 644 |
| | $ | 5,378 |
|
| Current state income tax refundable | | $ | — |
| | $ | 65 |
|
| Current state income tax payable | | $ | 1,181 |
| | $ | — |
|
AtAs of December 31, 2016,2019, the Company estimated its federal net operating loss (“NOL”) carryforward at $540.2$3.3 million which includes unrecognized excess income tax benefits associated with stock awards of $126.7and state NOL carryforwards at $77.8 million. The Company also has federal research and development (“R&D&D”) and AMT credit carryforwards of $7.2 million.$7.4 million and $4.3 million, respectively. The majority of federal NOL carryforward begins toNOLs do not expire in 2031but the state NOLs and thestate tax credits expire between 2021 and 2038. The federal R&D credit carryforwards expire between 2028 and 2033.2035. The Company’s alternative minimum tax (“AMT”)AMT credit carryforward of $5.6 million does not expire. State NOL carryforwards were $184.6 million and state tax credits were $528,000 as of December 31, 2016. State NOLs and credits expire between 2017 and 2037.are expected to be fully refunded by 2022. The Company’s current valuation allowance relates to state NOL carryforwards and state tax credits, which the Company anticipates willare expected to expire before they can be utilized. The change in the valuation allowance from 2015 to 2016 primarily relates to anticipated utilization of accumulated charitable contributions and an allocable change to the Company’s mix of state apportioned losses and the anticipated utilization of state cumulative NOLs.
FederalRecorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxestaxes. These differences primarily duerelate to the effect of state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, R&D credits, and accumulated impactsthe cumulative impact of other smaller permanent differences, and is reported as follows:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands) |
| Federal statutory tax expense (benefit) | $ | (48,519 | ) | | $ | 136,873 |
| | $ | (120,335 | ) |
| Increase (decrease) in tax resulting from: | | | | | |
| Federal tax reform changes - 2017 Tax Act | — |
| | — |
| | (63,675 | ) |
| State tax expense (benefit) (net of federal benefit) | 260 |
| | 2,771 |
| | (3,286 | ) |
| Change in valuation allowance | (13 | ) | | 105 |
| | (2,727 | ) |
| Employee share-based compensation | 3,346 |
| | 2,508 |
| | 8,190 |
|
| Other | 883 |
| | 1,113 |
| | (1,137 | ) |
| Income tax expense (benefit) | $ | (44,043 | ) | | $ | 143,370 |
| | $ | (182,970 | ) |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Federal statutory tax expense (benefit) | $ | (420,671 | ) | | $ | (253,001 | ) | | $ | 372,644 |
|
| Increase (decrease) in tax resulting from: | | | | | |
| State tax expense (benefit) (net of federal benefit) | (17,549 | ) | | (21,583 | ) | | 21,350 |
|
| Change in valuation allowance | (5,059 | ) | | 3,148 |
| | 2,245 |
|
| Research and development credit | — |
| | (1,971 | ) | | — |
|
| Other | (893 | ) | | (1,744 | ) | | 2,409 |
|
| Income tax expense (benefit) | $ | (444,172 | ) | | $ | (275,151 | ) | | $ | 398,648 |
|
Acquisitions, divestitures, drilling activity, and basis differentials, impactingwhich impact the prices received for oil, gas, and NGLs, impact the apportionment of taxable income to the states where the Company owns oil and gas properties. As these factors change, the Company’s state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total state income tax expense (benefit) reported in the current year. Items affecting state apportionment factors are evaluated upon completion of the prior year income tax return, and after significant acquisitions and divestitures, orif there are significant changes in drilling activity, or if estimated state revenue occurschanges occur during the year. In 2016, mostAs a result of this activity occurred inthe 2018 divestitures, the Company’s state apportionment rate reflects its significant Texas presence.
During the fourth quarter.
The Company and its subsidiaries file federal income tax returns and various state income tax returns. With an exception for activity related to its 2003 tax year,quarter of 2019, the Company claimed and received a $7.7 million refund for a portion of its deferred AMT credit carryover. An additional refund of $3.8 million is expected to be claimed in 2020. For all years before 2015, the Company is generally no longer subject to United States federal or state income tax examinations by these tax authorities for years before 2013. The Company recorded an additional $2.0 million net R&D credit in 2015 as a result of its R&D credit settlement with the IRS Appeals Office. During 2016, the Company’s 2007 - 2011 IRS examination was finalized, as was the 2013 IRS audit of the SM-Mitsui Tax Partnership with no material adjustments to previously recorded amounts.authorities.
The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible amount associated with income taxes. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2017.2020.
The total amount recorded for unrecognized tax benefits is presented below:for each of the years ended December 31, 2019, 2018, and 2017, was $446,000.
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Beginning balance | $ | 2,782 |
| | $ | 1,582 |
| | $ | 2,358 |
|
| Additions for tax positions of prior years | 9 |
| | 1,200 |
| | 140 |
|
| Settlements | (2,345 | ) | | — |
| | (916 | ) |
| Ending balance | $ | 446 |
| | $ | 2,782 |
| | $ | 1,582 |
|
Note 5 – Long-Term Debt
Revolving Credit FacilityAgreement
The Company’s FifthOn September 19, 2019, the Company and its lenders entered into the Second Amendment to the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) provideswhich permitted the Company to enter into swap agreements with respect to the price of electricity in order to minimize exposure to electrical price volatility. As of December 31, 2019, the Credit Agreement provided for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, and has a maturity date of December 10, 2019. During 2016, the following amendments were made to the Credit Agreement:
On April 8, 2016, as part of the regular, semi-annual borrowing base redetermination process, the Company entered into a Sixth Amendment to the Credit Agreement, which reduced the Company’s borrowing base to $1.25of $1.6 billion, from $2.0 billion at December 31, 2015. This expected reduction was primarily due to a decline in commodity prices, which resulted in a decrease in the Company’s proved reserves as of December 31, 2015. The amendment also reduced the aggregate lender commitments to $1.25 billion, and changed the required percentage of oil and gas properties subject to a mortgage to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Further, this amendment revised certain of the Company’s covenants under the Credit Agreement and modified the borrowing base utilization grid, as discussed below. The Company incurred approximately $3.1 million in deferred financing costs associated with this amendment to the Credit Agreement.
On August 8, 2016, the Company entered into a Seventh Amendment to the Credit Agreement to allow for capped call transactions.
Upon issuing the Senior Convertible Notes and 2026 Notes (as defined and discussed below) during the third quarter of 2016, the Company’s borrowing base and aggregate lender commitments were reduced to $1.1of $1.2 billion.
On September 30, 2016, as part of the regular, semi-annual borrowing base redetermination process, the Company entered into an Eighth Amendment to the Credit Agreement, which increased the Company’s borrowing base to $1.35 billion and the aggregate lender commitments to $1.25 billion due to an increase in commodity prices and the value of the proved reserves associated with the Rock Oil Acquisition.
On December 1, 2016, the Company’s borrowing base and aggregate lender commitments were reduced to $1.17 billion as a result of closing the sale of the Company’s Raven/Bear Den assets.
As a result of the various reductions to the Company’s borrowing base and aggregate lender commitments throughout 2016, the Company recorded approximately $2.5 million of expense related to the acceleration of unamortized deferred financing costs for the year ended December 31, 2016.
The borrowing base is subject to regular, semi-annual redetermination, processand considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve reportreport; and (b) commodity derivative contracts, each as determined by the Company’s lender group. The next scheduled borrowing base redetermination date is April 1, 2017,2020.
The Credit Agreement is scheduled to mature on the earlier of September 28, 2023, (the “Scheduled Maturity Date”), and August 16, 2022, to the extent that, on or before such date, the Company’s outstanding 2022 Senior Notes are not repurchased, redeemed, or refinanced to have a maturity date at least 91 days after the Scheduled Maturity Date unless, on August 16, 2022, both (i) the aggregate outstanding principal amount of the 2022 Senior Notes is not more than $100.0 million and (ii) after giving pro forma effect to the repayment in full at maturity of the 2022 Senior Notes then outstanding, the aggregate amount of unrestricted cash and certain types of unrestricted investments held by the Company expects a reduction toand its borrowing base as a resultConsolidated Restricted Subsidiaries plus the amount of unused availability under the anticipated sale of its outside-operated Eagle Ford shale assets and the decrease in proved reservesCredit Agreement is at December 31, 2016.
least $300.0 million.
The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. FinancialThe financial covenants under the Credit Agreement require that the Company’s (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which used annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending December 31, 2018, through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of each of the Company’sany fiscal quarters, the Company’s (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0.quarter. The Company was in compliance with all financial and non-financial covenants under the Credit Agreement as of December 31, 2016,2019, and through the filing date of this report.
Interest and commitment fees associated with the credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at the London Interbank Offered RateLIBOR, plus the applicable margin from the utilization table below,grid, and Alternate Base Rate (“ABR”)ABR and swinglineSwingline loans accrue interest at the primea market-based floating rate, plus the applicable margin from the utilization table below.grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense inline item on the accompanying statements of operations. The borrowing base utilization grid underas set forth in the Credit Agreement is as follows:
|
| | | | | | | | | | | | | | |
| Borrowing Base Utilization Percentage | <25% | | ≥25% <50% | | ≥50% <75% | | ≥75% <90% | | ≥90% |
Eurodollar Loans (1) | 1.500 | % | | 1.750 | % | | 2.000 | % | | 2.250 | % | | 2.500 | % |
| ABR Loans or Swingline Loans | 0.500 | % | | 0.750 | % | | 1.000 | % | | 1.250 | % | | 1.500 | % |
| Commitment Fee Rate | 0.375 | % | | 0.375 | % | | 0.500 | % | | 0.500 | % | | 0.500 | % |
____________________________________________
|
| | | | | | | | | | | | | | | |
| Borrowing Base Utilization Percentage | | <25% | | ≥25% <50% | | ≥50% <75% | | ≥75% <90% | | ≥90% |
| Eurodollar Loans | | 1.750 | % | | 2.000 | % | | 2.250 | % | | 2.500 | % | | 2.750 | % |
| ABR Loans or Swingline Loans | | 0.750 | % | | 1.000 | % | | 1.250 | % | | 1.500 | % | | 1.750 | % |
| Commitment Fee Rate | | 0.300 | % | | 0.300 | % | | 0.350 | % | | 0.375 | % | | 0.375 | % |
| |
(1) | The Company’s Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it shall no longer be used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the borrower. |
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of February 15, 2017,6, 2020, December 31, 2016,2019, and December 31, 2015:
| | | | As of February 15, 2017 | | As of December 31, 2016 | | As of December 31, 2015 | As of February 6, 2020 | | As of December 31, 2019 | | As of December 31, 2018 |
| | (in thousands) | (in thousands) |
Credit facility balance (1) | $ | 103,500 |
| | $ | — |
| | $ | 202,000 |
| |
Revolving credit facility (1) | | $ | 113,500 |
| | $ | 122,500 |
| | $ | — |
|
Letters of credit (2) | 200 |
| | 200 |
| | 200 |
| — |
| | — |
| | 200 |
|
| Available borrowing capacity | 1,061,300 |
| | 1,164,800 |
| | 1,297,800 |
| 1,086,500 |
| | 1,077,500 |
| | 999,800 |
|
| Total aggregate lender commitment amount | $ | 1,165,000 |
| | $ | 1,165,000 |
| | $ | 1,500,000 |
| $ | 1,200,000 |
| | $ | 1,200,000 |
| | $ | 1,000,000 |
|
| |
(1) | Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $5.9 million and $4.9$6.4 million as of December 31, 2016,2019, and 2015,2018, respectively. These costs are being amortized over the term of the credit facility on a straight-line basis. |
| |
(2) | Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018, was released effective January 8, 2019. |
Senior Notes
The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of December 31, 20162019, and 2018, and 2015, consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
| | Principal Amount | | Unamortized Deferred Financing Costs | | Principal Amount, Net of Unamortized Deferred Financing Costs | | Principal Amount | | Unamortized Deferred Financing Costs | | Principal Amount, Net of Unamortized Deferred Financing Costs |
| | (in thousands) |
| 6.125% Senior Notes due 2022 | $ | 476,796 |
| | $ | 2,920 |
| | $ | 473,876 |
| | $ | 476,796 |
| | $ | 3,921 |
| | $ | 472,875 |
|
| 5.0% Senior Notes due 2024 | 500,000 |
| | 3,766 |
| | 496,234 |
| | 500,000 |
| | 4,688 |
| | 495,312 |
|
| 5.625% Senior Notes due 2025 | 500,000 |
| | 4,903 |
| | 495,097 |
| | 500,000 |
| | 5,808 |
| | 494,192 |
|
| 6.75% Senior Notes due 2026 | 500,000 |
| | 5,571 |
| | 494,429 |
| | 500,000 |
| | 6,407 |
| | 493,593 |
|
| 6.625% Senior Notes due 2027 | 500,000 |
| | 6,601 |
| | 493,399 |
| | 500,000 |
| | 7,533 |
| | 492,467 |
|
| Total | $ | 2,476,796 |
| | $ | 23,761 |
| | $ | 2,453,035 |
| | $ | 2,476,796 |
| | $ | 28,357 |
| | $ | 2,448,439 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2016 | | 2015 |
| | Principal Amount | | Unamortized Deferred Financing Costs | | Senior Notes, Net of Unamortized Deferred Financing Costs | | Principal Amount | | Unamortized Deferred Financing Costs | | Senior Notes, Net of Unamortized Deferred Financing Costs |
| | (in thousands) |
| 6.50% Senior Notes due 2021 | $ | 346,955 |
| | $ | 3,372 |
| | $ | 343,583 |
| | $ | 350,000 |
| | $ | 4,106 |
| | $ | 345,894 |
|
| 6.125% Senior Notes due 2022 | 561,796 |
| | 6,979 |
| | 554,817 |
| | 600,000 |
| | 8,714 |
| | 591,286 |
|
| 6.50% Senior Notes due 2023 | 394,985 |
| | 4,436 |
| | 390,549 |
| | 400,000 |
| | 5,231 |
| | 394,769 |
|
| 5.0% Senior Notes due 2024 | 500,000 |
| | 6,533 |
| | 493,467 |
| | 500,000 |
| | 7,455 |
| | 492,545 |
|
| 5.625% Senior Notes due 2025 | 500,000 |
| | 7,619 |
| | 492,381 |
| | 500,000 |
| | 8,524 |
| | 491,476 |
|
| 6.75% Senior Notes due 2026 | 500,000 |
| | 8,078 |
| | 491,922 |
| | — |
| | — |
| | — |
|
| Total | $ | 2,803,736 |
| | $ | 37,017 |
| | $ | 2,766,719 |
| | $ | 2,350,000 |
| | $ | 34,030 |
| | $ | 2,315,970 |
|
The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; however, the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant.dividends. The Company was in compliance with all such covenants under its Senior Notes as of December 31, 2016,2019, and through the filing date of this report. All Senior Notes are registered under the Securities Act as of December 31, 2016.Act. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.
During the first quarter of 2016,On July 16, 2018, the Company repurchased in open market transactions a total of $46.3 million in aggregate principal amount of certain ofredeemed its 6.50%2021 Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023 for a settlement amount of $29.9 million, excluding interest, which resulted in a net gain on extinguishmentthe payment of debttotal cash consideration, including accrued interest, of approximately $15.7$355.9 million. This amount includes a gainAdditionally, during the third quarter of $16.4 million associated with2018, the discount realized upon repurchase, which was partially offset by approximately $700,000 related toCompany used the accelerationproceeds from the issuance of unamortized deferred financing costs. The Company canceled all repurchasedits 2027 Senior Notes, uponas discussed below, and cash settlement.
2019 Notes. On May 7, 2015,on hand to fund the Company commenced a cash tender offer for any and allredemption of $395.0 million of its outstanding 6.625%2023 Senior Notes due 2019 (“2019 Notes”) at a price of $1,036.88 per $1,000 of principal amount for all 2019 Notes tendered by May 20, 2015 (“Consent Payment Deadline”), and at a price of $1,006.88 per $1,000 of principal amount for all 2019 Notes properly tendered thereafter. On the Consent Payment Deadline, the Company received tenders and consents from the holders of approximately $242.9$85.0 million in aggregate principal amount, or approximately 69%, of its outstanding 2019 Notes in connection with the cash tender offer. Following its entry into the supplemental indenture dated as of May 21, 2015, to the indenture dated as of February 7, 2011, between the2022 Senior Notes. The Company and U.S. Bank National Association, as trustee, the Company accepted the 2019 Notes tendered as of the Consent Payment Deadline in exchange for payment ofpaid total consideration, including accrued interest, of approximately $256.2$497.8 million underto complete these transactions. As a result of the Tender Offerredemption of the 2021 Senior Notes, and Consent Solicitation. On June 5, 2015,the cash tender offer and redemption of all of the 2023 Senior Notes and a portion of the 2022 Senior Notes, the Company accepted $1.5 million of 2019 Notes tendered after the Consent Payment Deadline in exchange for payment of total consideration, including accrued interest, of approximately $1.6 million. On June 22, 2015, the Company redeemed the remaining outstanding 2019 Notes atrecorded a redemption price of 103.313% of the principal amount for payment of total consideration, including accrued interest, of approximately $111.5 million.
The Company recorded acombined loss on extinguishment of debt related to the tender offer and redemption of its 2019 Notes of approximately $16.6$26.7 million for the year ended December 31, 2015.2018. This amount includes approximately $12.5included combined premiums paid of $20.4 million associated with the premium paid for the tender offer and redemption$6.3 million of the 2019 Notes and approximately $4.1 million related to the acceleration ofaccelerated unamortized deferred financing costs.costs for the redemption.
20212022 Senior Notes. On November 8, 2011, the Company issued $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021 at par, which mature on November 15, 2021. The Company received net proceeds of $343.1 million after deducting fees of $6.9 million, which are being amortized as deferred financing costs over the life of the 2021 Notes. During the first quarter of 2016, the Company repurchased $3.1 million in aggregate principal amount of its 2021 Notes for a settlement amount of $2.3 million, excluding interest.
2022 Notes. On November 17, 2014, the Company issued $600.0 million in aggregate principal amount of 6.125% Senior Notes due 2022 at par, which mature on November 15, 2022. The Company received net proceeds of $590.0 million after deducting fees of $10.0 million, which are being amortized as deferred financing costs over the life of the 2022 Senior Notes. The net proceeds were used to repay outstanding borrowings under the Company’s credit facility and for general corporate purposes. During the first quarter of 2016, the Company repurchased $38.2 million in aggregate principal amount of its 2022 Senior Notes for a
settlement amount of $24.3 million, excluding interest.
2023 Notes. On June 29, 2012, During the third quarter of 2018, through the tender offer discussed above, the Company issued $400.0retired $85.0 million in aggregate principal amount of 6.50%its 2022 Senior Notes due 2023 at par, which mature on January 1, 2023. The Company received net proceedsfor total consideration, including accrued interest, of $392.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2023$89.5 million.
2024 Senior Notes. During the first quarter of 2016, the Company repurchased $5.0 million in aggregate principal amount of its 2023 Notes for a settlement amount of $3.3 million, excluding interest.
2024 Notes. On May 20, 2013, the Company issued $500.0 million in aggregate principal amount of 5.0% Senior Notes due 2024 at par, which mature on January 15, 2024. The Company received net proceeds of $490.2 million after deducting fees of $9.8 million, which are being amortized as deferred financing costs over the life of the 2024 Senior Notes.
2025 Senior Notes. On May 21, 2015, the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 at par, which mature on June 1, 2025. The Company received net proceeds of $491.0 million after deducting fees of $9.0 million, which are being amortized as deferred financing costs over the life of the 2025 Senior Notes.
2026 Senior Notes. The net proceeds were used to fund the consideration paid to the tendering holders of the 2019 Notes and to redeem the remaining untendered 2019 Notes, as well as repay outstanding borrowings under the Credit Agreement and for general corporate purposes.
2026 Notes. On September 12, 2016, the Company issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026, at par, (the “2026 Notes”), which mature on September 15, 2026. The Company received net proceeds of $491.6 million after deducting fees of $8.4 million, which are being amortized as deferred financing costs over the life of the 2026 Senior Notes.
2027 Senior Notes. On August 20, 2018, the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027, at par, which mature on January 15, 2027. The Company received net proceeds of $492.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. As discussed above, the net proceeds were used to partially fund the Rock Oil Acquisition that closed on October 4, 2016.tender offer and redemption of all of the Company’s 2023 Senior Notes and a portion of its 2022 Senior Notes.
Senior Convertible Notes
On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due 2021 (“the Senior Convertible Notes”), which mature on July 1, 2021.2021, unless earlier converted. The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company received net proceeds of $166.6 million after deducting fees of $5.9 million, of which a portion is being amortized over the life of the Senior Convertible Notes. The net proceeds were used to partially fund the Rock Oil Acquisition that closed on October 4, 2016, as well as pay the cost of the capped call transactions discussed below.
The Senior Convertible Notes mature on July 1, 2021, unless earlier repurchased or converted. Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under the following circumstances: (1) during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2016, if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (2) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price (as defined in the indenture) per $1,000 principal amount of Notes for each trading day of the measurement period was less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (3) upon the occurrence of specified corporate events. On or after January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time, regardless of the foregoing circumstances.time. The Company may not redeem the Senior Convertible Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment.
The Company has initially elected a net-settlement method to satisfy its conversion obligation, which allowswould result in the Company to settlesettling the principal amount in cash with any excess conversion in shares of the Senior Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares.Company’s common stock. The Senior Convertible Notes were not convertible at the option of holders as of December 31, 2016,2019, or through the filing date of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of December 31, 2016,2019, did not exceed the principal amount.
In accounting forUpon the issuance of the Senior Convertible Notes, at issuance, the Company allocated proceeds fromrecorded $132.3 million as the Senior Convertible Notes into debt and equity components according to the authoritative accounting guidance for convertible debt instruments that may be fully or partially settled in cash upon conversion. The initial carrying amount of the debt component, which approximatesapproximated its fair value at issuance, and, was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25%. The $40.2 million excess of the principal amount of the Senior Convertible Notes over the fair value of the debt component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The Company incurred transaction costs of $5.9 million relating to the issuance of the Senior Convertible Notes, which were allocated between the debt and equity components in proportion to their determined fair value amounts. The debt discount and debt-related issuance costs are amortized to the carryingprincipal value of the Senior Convertible Notes as interest
expense through the maturity date of July 1, 2021. Upon issuance of the Senior Convertible Notes, the Company recorded $132.3 million as long-term debt and $40.2 million as additional paid-in capital in stockholders’ equity in the accompanying balance sheets. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $3.7$11.0 million, $10.5 million, and $9.9 million for the yearyears ended December 31, 2016.2019, 2018, and 2017, respectively.
The net carrying amount of the liability component of the Senior Convertible Notes, as reflectednet of unamortized discount and deferred financing costs line on the accompanying balance sheets consisted of the following as of December 31, 2016:
2019 and 2018:
|
| | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Principal amount of Senior Convertible Notes | $ | 172,500 |
| | $ | 172,500 |
|
| Unamortized debt discount | (13,861 | ) | | (22,313 | ) |
| Unamortized deferred financing costs | (1,376 | ) | | (2,293 | ) |
| Senior Convertible Notes, net of unamortized discount and deferred financing costs | $ | 157,263 |
| | $ | 147,894 |
|
|
| | | |
| | As of December 31, 2016 |
| | (in thousands) |
| Principal amount of Senior Convertible Notes | $ | 172,500 |
|
| Unamortized debt discount | (37,513 | ) |
| Unamortized deferred financing costs | (4,131 | ) |
| Net carrying amount | $ | 130,856 |
|
TheAs of both December 31, 2019 and 2018, the net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets consisted of the following as of December 31, 2016:
|
| | | |
| | As of December 31, 2016 |
| | (in thousands) |
| Equity component due to allocation of proceeds to equity | $ | 40,217 |
|
| Less: related issuance costs | (1,375 | ) |
| Less: deferred tax liability | (5,267 | ) |
| Net carrying amount | $ | 33,575 |
|
was $33.6 million. There have been no changes to this amount since issuance.
If the Company undergoes a fundamental change, as defined by the governing indenture, holders of the Senior Convertible Notes may require the Company to repurchase for cash all or any portion of their notes at a fundamental change repurchase price equal to 100% of the principal amount of the Senior Convertible Notes to be repurchased, plus accrued and unpaid interest. The indenture governing the Senior Convertible Notes contains customary events of default with respect to the Senior Convertible Notes, including that upon certain events of default, the trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding Senior Convertible Notes by notice to the Company, may declare 100% of the principal and accrued and unpaid interest, if any, due and payable immediately. In case of certain events of bankruptcy, insolvency or reorganization involving the Company or a significant subsidiary, 100% of the principal and accrued and unpaid interest on the Senior Convertible Notes will automatically become due and payable.
The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as of December 31, 2016,2019, and through the filing date of this report.
Capped Call Transactions
In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of such issuance. The aggregate cost of the capped call transactions was approximately $24.2 million. The capped call transactions are generally expected to reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in excess of the principal amount of converted Senior Convertible Notes in the event that the market price per share of the Company’s common stock as measured under the terms of the capped call transactions (“market price per share”), is greater than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible Notes and is subject to anti-dilution adjustments substantially similar to those applicable to the conversion rate of the Senior Convertible Notes. The cap price of the capped call transactions wasis initially $60.00 per share, and is subject to certain adjustments under the terms of the capped call transactions.share. If however, the market price per share exceeds the cap price of the capped call transactions, there wouldcould be dilution and/or there would not be an offset of such potential cash payments, in each case, topayments. The Company classified the extent that such market price per share exceeds the cap price ofcosts associated with the capped call transactions.
The Company evaluated the capped call transactions under authoritative accounting guidance and determined that they should be accounted for as separate transactions and classified as equity instruments with no recurring fair value measurement recorded.
Capitalized Interest
Capitalized interest costs for the Company for the years ended December 31, 2016, 2015,2019, 2018, and 2014, were $17.02017, totaled $18.5 million, $25.1$20.6 million, and $16.2$12.6 million, respectively.
Capitalized interest costs are included in total costs incurred. Please refer to Costs Incurred in Oil and Gas Producing Activities in Overview of the Companyin Part II, Item 7, and Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report.
Note 6 – Commitments and Contingencies
Commitments
The Company has entered into various agreements, which include drilling rig and completion service contracts of $31.1$34.1 million, gathering, processing, and transportation throughput, and delivery commitments of $970.9$218.5 million, office leases, including maintenance, of $50.1$28.3 million, fixed price contracts to purchase electricity of $53.2 million, and other miscellaneous contracts and leases of $6.0$15.5 million. The annual minimum payments for the next five years and total minimum payments thereafter are presented below:
|
| | | | |
| Years Ending December 31, | | Amount (in thousands) |
| 2020 | | $ | 102,550 |
|
| 2021 | | 94,494 |
|
| 2022 | | 73,826 |
|
| 2023 | | 41,661 |
|
| 2024 | | 12,349 |
|
| Thereafter | | 24,697 |
|
| Total | | $ | 349,577 |
|
|
| | | | |
| Years Ending December 31, | | Amount (1) (in thousands) |
| 2017 | | $ | 145,075 |
|
| 2018 | | 148,240 |
|
| 2019 | | 144,379 |
|
| 2020 | | 141,010 |
|
| 2021 | | 141,654 |
|
| Thereafter | | 337,745 |
|
| Total | | $ | 1,058,103 |
|
| |
(1)
| During the third quarter of 2015, the Company closed its office in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $2.7 million of total sublease income through 2019. |
Drilling Rig Contracts
and Completion Service Contracts. The Company has several drilling rig and completion service contracts in place to facilitate its drilling and completion plans. Early termination of these rig contracts asAs of December 31, 2016, would have resulted in termination penalties of $14.2 million, which would be in lieu of paying2019, the remainingCompany’s drilling rig and completion service contract commitments of $31.1totaled $34.1 million, included in the table above. For the years endedIf all of these contracts were terminated as of December 31, 2016, and 2015,2019, the Company incurred $8.7would avoid a portion of the contractual service commitments; however, the Company would be required to pay $26.3 million and $13.7 million, respectively, of expenses related to thein early termination fees. Excluded from these amounts are variable commitments and potential penalties determined by the number of drilling rig contracts or fees incurred for rigs placedcompletion crews the Company has in operation in a particular area under a completion service arrangement. As of December 31, 2019, potential penalties under this completion service agreement, which expires on standby, which are recorded in the other operating expenses line item in the accompanying statementsDecember 31, 2023, range from 0 to a maximum of operations.$13.4 million.
Pipeline Transportation Commitments
Commitments. The Company has gathering, processing, and transportation throughput, and delivery commitments with various third partiesthird-parties that require delivery of a minimum amount of naturaloil, gas, crude oil, NGLs, and produced water. As of December 31, 2016,2019, the Company has commitments to deliver a minimum of 1,46124 MMBbl of oil and 424 Bcf of natural gas 70through 2023, and 18 MMBbl of crude oil, 13 MMBbl of NGLs, and 25 MMBbl ofproduced water through 2034.2027. The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. As of December 31, 2016,2019, if the Company delivered no furtherfails to deliver any product, as applicable, the aggregate undiscounted deficiency payments total approximately $970.9 million through 2034. If a shortfall$218.5 million. This amount does not include deficiency payment estimates associated with approximately 16.5 MMBbl of future oil delivery commitments where the Company cannot predict with accuracy the amount and timing of these payments, as such payments are dependent upon the price of oil in effect at the time of settlement. Under certain of the Company’s commitments, if the Company is unable to deliver the minimum volume commitment for natural gas is projected, the Company has rights under certain contractsquantity from its production, it may deliver production acquired from third-parties to arrange for third party gas to be delivered, and such volumes would count towardsatisfy its minimum volume commitment.commitments.
Subsequent to December 31, 2016, the Company entered into a definitive agreement for the sale of its outside-operated Eagle Ford shale assets held for sale at December 31, 2016, and expects to close the transaction in the first quarter of 2017. Upon closing of the sale, the Company would no longer be subject to transportation throughput commitments totaling
514 Bcf of natural gas, 52 MMBbl of oil, and 13 MMBbl of NGLs, or $501.9 million of the potential undiscounted deficiency payments presented in the table above.
As of the filing date of this report, the Company does not expect to incur any material shortfalls.
Office Leases
Leases. The Company leases office space under various operating leases with terms extending as far as 2026. Rent expense net of sublease income, for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, was $5.2$5.5 million, $6.1$4.5 million, and $6.5$4.8 million, respectively.
Electrical Power Purchase Contracts. During the second quarter of 2019, the Company entered into a fixed price contract for the purchase of electrical power that increased the purchase commitment under an existing agreement. As of December 31, 2019, the Company had a commitment to purchase electrical power through 2027 with a total remaining obligation of $53.2 million.
Delivery and Purchase Commitments. During the second quarter of 2019, the Company executed an amendment to its existing sand sourcing agreement that created certain commitments and potential penalties that vary based on the amount of sand the Company uses in well completions occurring in a particular area. This amended sand sourcing agreement expires on December 31, 2023. As of December 31, 2019, potential penalties under this sand sourcing agreement range from 0 to a maximum of $10.0 million.
Drilling and Completion Commitments. The Company closed its officehas an agreement in Billings, Montana in November 2016place that includes minimum drilling and paid $3.2 millioncompletion requirements on certain leases. If these minimum requirements are not satisfied by March 31, 2020, the Company would be required to make a liquidated damage payment based on the lessordifference between actual development progress and the minimum development requirements. As of December 31, 2019, the Company did not expect to terminatemeet certain minimum development requirements.
In the lease, which is not reflectedfourth quarter of 2019, the Company recognized one-time charges associated with expected payments to lessors related to drilling and completion obligations and early termination fees for drilling rigs totaling $18.2 million. These amounts are included in the rentother operating expense amount above.
line item on the accompanying statements of operations.
Contingencies
The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of suchany pending litigation and claims willare not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.
Note 7 – Compensation Plans
Equity Incentive Compensation Plan
There are several components to the Company’s Equity Incentive Compensation Plan (“Equity Plan”) that are described in this section. Various types of equity awards have been granted by the Company in different periods.
As of December 31, 2016,2019, approximately 5.54.4 million shares of common stock remainedwere available for grant under the Equity Plan. The issuance of a direct share benefit, such as a share of common stock, a stock option, a restricted share, an RSU, or a PSU, counts as one1 share against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as two2 shares against the number of shares available to be granted under the Equity Plan based on the final performance multiplier. Stock options were issued out of the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan, both predecessors to the Equity Plan, although the last grant was in 2004, and all remaining stock options were exercised during the year ended December 31, 2014.
Performance Share Units
The Company grants PSUs to eligible employees as part of its long-term equity compensation program.Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0%0 to 200% of2 times the number of PSUs awarded and is determined based on certain performance criteria over a three-year measurementperformance period. The performance criteria forPSUs generally vest on the PSUs are based on a combinationthird anniversary of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performancedate of the Company’s TSR comparedgrant or upon other triggering events as set forth in the Equity Plan. Employees who are retirement eligible at the time a PSU award was granted, vest in each portion of that award equally in six-month increments over a three-year period beginning at grant date. Retirement eligible employees must stay with the annualized TSRCompany through the entire six-month vesting period to receive that increment of certain peer companies forvesting and any non-vested portions of a PSU award will be forfeited when the performance period. Compensation expense for PSUs is recognized within general and administrative and exploration expense overemployee leaves the vesting periods of the respective awards.Company.
The fair value of PSUs wasis measured at the grant date with a stochastic process methodMonte Carlo simulation using the Geometricgeometric Brownian Motion Modelmotion (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the path the stock price willmay take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three-year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers.
For PSUs granted in 2017, which the Company has determined to be equity awards, the settlement criteria include a combination of the Company’s Total Shareholder Return (“TSR”) on an absolute basis, and the Company’s TSR relative to the TSR of certain peer companies over the associated three-year performance period. The fair value of the PSUs granted in 2017 was measured on the grant date using the GBM Model. As these awards depend entirely on market-based settlement criteria, the associated compensation expense is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting period of the awards.
For PSUs granted in 2018 and 2019, the settlement criteria include a combination of the Company’s TSR relative to the TSR of certain peer companies and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance period. In addition to these performance measures, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at 1 times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair value of the PSUs granted in 2018 and 2019 was measured on the applicable grant dates using the GBM Model, with the assumption that the associated CRTCI performance condition will be met at the target amount at the end of the respective performance periods. Compensation expense for PSUs granted in 2018 and 2019 is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. As these awards depend on a combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected CRTCI performance relative to the applicable peer companies.
The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total compensation expense recorded for PSUs was $11.0$10.9 million, $10.6$10.3 million, and $16.0$9.7 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively. As of December 31, 2016,2019, there was $15.9 million of total unrecognized expense related to PSUs, which is being amortized through 2019.2022.
A summary of the status and activity of non-vested PSUs is presented in the following table:
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| | PSUs | | Weighted-Average Grant-Date Fair Value | | PSUs | | Weighted-Average Grant-Date Fair Value | | PSUs | | Weighted-Average Grant-Date Fair Value | PSUs (1) | | Weighted-Average Grant-Date Fair Value | | PSUs (1) | | Weighted-Average Grant-Date Fair Value | | PSUs (1) | | Weighted-Average Grant-Date Fair Value |
Non-vested at beginning of year (1) | 626,328 |
| | $ | 61.81 |
| | 433,660 |
| | $ | 73.63 |
| | 572,469 |
| | $ | 66.07 |
| 1,711,259 |
| | $ | 20.68 |
| | 1,533,491 |
| | $ | 22.97 |
| | 828,923 |
| | $ | 43.25 |
|
Granted (1) | 447,971 |
| | $ | 26.56 |
| | 320,753 |
| | $ | 45.34 |
| | 202,404 |
| | $ | 94.66 |
| 793,125 |
| | $ | 12.80 |
| | 572,924 |
| | $ | 24.45 |
| | 977,731 |
| | $ | 15.86 |
|
Vested (1) | (130,353 | ) | | $ | 64.17 |
| | (76,438 | ) | | $ | 51.76 |
| | (206,830 | ) | | $ | 64.79 |
| (346,021 | ) | | $ | 26.32 |
| | (233,102 | ) | | $ | 44.25 |
| | (94,338 | ) | | $ | 85.85 |
|
Forfeited (1) | (115,023 | ) | | $ | 55.59 |
| | (51,647 | ) | | $ | 73.62 |
| | (134,383 | ) | | $ | 86.72 |
| (135,778 | ) | | $ | 16.98 |
| | (162,054 | ) | | $ | 21.79 |
| | (178,825 | ) | | $ | 44.99 |
|
Non-vested at end of year(1) | 828,923 |
| | $ | 43.25 |
| | 626,328 |
| | $ | 61.81 |
| | 433,660 |
| | $ | 73.63 |
| 2,022,585 |
| | $ | 16.87 |
| | 1,711,259 |
| | $ | 20.68 |
| | 1,533,491 |
| | $ | 22.97 |
|
| |
(1) | The number of awards assumes a multiplier of one.1. The final number of shares of common stock issued may vary depending on the three-year performance multiplier, which ranges from zero0 to two.2. |
The fair value of the PSUs granted in 2019, 2018, and 2017 was $10.2 million, $14.0 million, and $15.5 million, respectively.
During the years ended December 31, 2019, 2018, and 2017, PSUs that were granted in 2016, 2015, and 2014, respectively did not satisfy the minimum performance requirements. This resulted in a multiplier of 0 times and therefore 0 shares of common stock were issued upon settlement.
The total fair value of PSUs that vested during the years ended December 31, 2019, 2018, and 2017 was $11.9$9.1 million, $14.5$10.3 million, and $19.2$8.1 million, respectively.
Employee Restricted Stock Units
The PSUs granted in 2015 and 2014 will remain unvested untilCompany grants RSUs to eligible persons as part of its Equity Plan. Each RSU represents a right to receive 1 share of the thirdCompany’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest one-third of the total grant on each anniversary date of their issuance, at which time they will fully vest, unless the employee is retirement eligiblegrant over a three-year vesting period or upon other triggering events as set forth in which case the PSUs vest immediately upon attainment of retirement age. PSUs granted in 2016 fully vest on the third anniversary of the date of the grant; however, employeesEquity Plan. Employees who are retirement eligible at the time a PSUan RSU award wasis granted, vest in each portion of that award equally in six-month increments over a three-year period beginning at grant date. Retirement eligible employees must stay with the companyCompany through the entire six-month vesting period to receive that increment of vesting and any unvestednon-vested portions of a PSUan RSU award will be forfeited when the employee leaves the company. Company.
A summary of the shares of common stock issued to settle PSUs is presented in the table below:
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
Shares of common stock issued to settle PSUs (1) | 44,870 |
| | 288,962 |
| | 130,163 |
|
| Less: shares of common stock withheld for income and payroll taxes | (14,809 | ) | | (100,683 | ) | | (45,042 | ) |
| Net shares of common stock issued | 30,061 |
| | 188,279 |
| | 85,121 |
|
| | | | | | |
| Multiplier earned | 0.2 |
| | 1.0 |
| | 0.55 |
|
| |
(1)
| During the years ended December 31, 2016, 2015, and 2014, the Company issued shares of common stock for PSUs granted in 2013, 2012, and 2011. The Company and the majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. |
The total fair value of PSUs that vested during the years ended December 31, 2016, 2015, and 2014 was $8.4 million, $4.0 million, and $13.4 million, respectively.
Restricted Stock Units
The Company grants RSUs to eligible employees as part of its long-term equity incentive compensation program. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the award.
Total compensation expense recorded for RSUs for the years ended December 31, 2016, 2015, and 2014, was $11.9 million, $13.4 million, and $13.9 million, respectively. As of December 31, 2016, there was $14.4 million of total unrecognized expense related to unvested RSU awards, which is being amortized through 2019. The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for employee RSUs for the years ended December 31, 2019, 2018, and 2017, was $11.1 million, $10.8 million, and $10.3 million, respectively. As of December 31, 2019, there was $16.9 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2022.
A summary of the status and activity of non-vested RSUs granted to employees is presented below:in the following table:
|
| | | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | RSUs | | Weighted- Average Grant-Date Fair Value | | RSUs | | Weighted- Average Grant-Date Fair Value | | RSUs | | Weighted- Average Grant-Date Fair Value |
| Non-vested at beginning of year | 1,243,163 |
| | $ | 21.50 |
| | 1,244,262 |
| | $ | 20.25 |
| | 604,116 |
| | $ | 37.39 |
|
| Granted | 978,932 |
| | $ | 12.36 |
| | 583,552 |
| | $ | 25.77 |
| | 1,020,780 |
| | $ | 16.64 |
|
| Vested | (466,535 | ) | | $ | 21.94 |
| | (407,529 | ) | | $ | 24.30 |
| | (246,025 | ) | | $ | 43.99 |
|
| Forfeited | (223,429 | ) | | $ | 18.16 |
| | (177,122 | ) | | $ | 17.26 |
| | (134,609 | ) | | $ | 26.38 |
|
| Non-vested at end of year | 1,532,131 |
| | $ | 16.01 |
| | 1,243,163 |
| | $ | 21.50 |
| | 1,244,262 |
| | $ | 20.25 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | RSUs | | Weighted- Average Grant-Date Fair Value | | RSUs | | Weighted- Average Grant-Date Fair Value | | RSUs | | Weighted- Average Grant-Date Fair Value |
| Non-vested at beginning of year | 543,737 |
| | $ | 55.01 |
| | 515,724 |
| | $ | 68.29 |
| | 580,431 |
| | $ | 57.05 |
|
| Granted | 417,065 |
| | $ | 28.08 |
| | 356,246 |
| | $ | 43.72 |
| | 234,560 |
| | $ | 83.98 |
|
| Vested | (241,363 | ) | | $ | 58.06 |
| | (278,289 | ) | | $ | 63.12 |
| | (253,031 | ) | | $ | 58.19 |
|
| Forfeited | (115,323 | ) | | $ | 43.52 |
| | (49,944 | ) | | $ | 66.53 |
| | (46,236 | ) | | $ | 62.06 |
|
| Non-vested at end of year | 604,116 |
| | $ | 37.39 |
| | 543,737 |
| | $ | 55.01 |
| | 515,724 |
| | $ | 68.29 |
|
The fair value of RSUs granted to eligible employees in 2016, 2015,2019, 2018, and 20142017 was $11.7$12.1 million, $15.6$15.0 million, and $19.7$17.0 million, respectively. The RSUs granted in 2015 and 2014 vest one-third of the total grant on each anniversary of the grant dates, unless the employee is retirement eligible in which case the RSUs vest immediately upon attainment of retirement age. The RSUs granted in 2016 vest one-third of the total grant on each anniversary of the grant dates, unless the employee is retirement eligible in which case the RSUs vest in each portion of that award equally in six-month increments over a three-year period beginning at grant date. Retirement eligible employees must stay with the company through the entire six-month vesting period to receive that increment of vesting and any unvested portions of a RSU award will be forfeited when the employee leaves the company.
A summary of the shares of common stock issued to settle employee RSUs is presented in the table below: |
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
Shares of common stock issued to settle RSUs (1) | 466,535 |
| | 407,529 |
| | 246,025 |
|
| Less: shares of common stock withheld for income and payroll taxes | (132,136 | ) | | (115,784 | ) | | (74,747 | ) |
| Net shares of common stock issued | 334,399 |
| | 291,745 |
| | 171,278 |
|
____________________________________________
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
Shares of common stock issued to settle RSUs (1) | 241,363 |
| | 278,289 |
| | 253,031 |
|
| Less: shares of common stock withheld for income and payroll taxes | (72,181 | ) | | (91,045 | ) | | (81,434 | ) |
| Net shares of common stock issued | 169,182 |
| | 187,244 |
| | 171,597 |
|
| |
(1) | During the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, the Company issued shares of common stock forto settle RSUs that related to awards granted in previous years. The Company and thea majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. |
The total fair value of employee RSUs that vested during the years ended December 31, 2016, 2015,2019, 2018, and 20142017 was $14.0$10.2 million, $17.6$9.9 million, and $14.7$10.8 million, respectively.
Stock Option Grants
The Company previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options occurred on December 31, 2004. Stock options to purchase shares of the Company’s common stock were granted to eligible employees and members of the Board of Directors. All options granted under the option plans were granted at exercise prices equal to the respective closing market price of the Company’s underlying common stock on the grant dates. All stock options granted under the option plans were exercisable for a period of up to 10 years from the date of grant. The remaining options from the 2004 grant were exercised during the year ended December 31, 2014, and thus there is no unrecognized compensation expense related to stock option awards.
A summary of activity associated with the Company’s Stock Option Plans during the year ended December 31, 2014, is presented in the following table:
|
| | | | | | | | | | |
| | Shares | | Weighted-Average Exercise Price | | Aggregate Intrinsic Value |
| For the year ended December 31, 2014 | | | | | |
| Outstanding, start of year | 39,088 |
| | $ | 20.87 |
| | $ | — |
|
| Exercised | (39,088 | ) | | $ | 20.87 |
| | $ | 1,993,726 |
|
| Forfeited | — |
| | $ | — |
| | $ | — |
|
| Outstanding, end of year | — |
| | $ | — |
| | $ | — |
|
| Vested and exercisable at end of year | — |
| | $ | — |
| | $ | — |
|
The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing model. Cash received from stock options exercised for the year ended December 31, 2014, was $4.0 million.
Cash flows resulting from excess tax benefits are classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised options in excess of the deferred tax asset attributable to stock compensation costs for such equity awards. The Company recorded no excess tax benefits for the years ended December 31, 2016, 2015, and 2014.
Director Shares
In 2016, 2015,2019, 2018, and 2014,2017, the Company issued 53,473, 39,903,96,719, 63,741, and 27,67771,573 shares, respectively, of its common stock to its non-employee directors under the Company’s Equity Plan. TheIn 2017, the Company recorded $2.0 million of compensation expense for the year ended December 31, 2016, relatedissued 8,794 RSUs to director shares issued, and $1.6 million for each ofa non-employee director. For the years ended December 31, 2015,2019, 2018, and 2014.2017, the Company recorded $1.2 million, $1.7 million, and $1.6 million, respectively, of compensation expense related to director shares and RSUs issued.
Beginning with the awards granted in 2016, allAll shares issued to non-employee directors fully vest on December 31st of the year granted. Prior to 2016, all shares of common stockThe RSUs issued to the Company’sa non-employee directors were earned over the one-year service period following the date of grant, unless five years of service had been provided to the Company by the director in which case that director’s shares2017 fully vested on December 31, 2017, and will settle upon the earlier to occur of the completion of the one year service periodMay 25, 2027, or the director retiringresigning from the Board of Directors.
Employee Stock Purchase Plan
Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of 85% of the closing pricefair market value of the stock on either the first or last day of the offering period or 85% of the closing price of the stock on the purchase date, and shares issued under the ESPP have no restriction period. The ESPP is intended to qualify under Section 423 of the IRC.Internal Revenue Code (the “IRC”). The Company had approximately 0.71.3 million shares of its common stock available for issuance under the ESPP as of December 31, 2016.2019. There were 218,135, 197,214,314,868, 199,464, and 83,136186,665 shares issued under the ESPP in 2016, 2015,2019, 2018, and 2014,2017, respectively. Total proceeds to the Company for the issuance of these shares were $4.2$3.2 million $4.8 million, and $4.1 million for each of the years ended December 31, 2016, 2015,2019, and 2014, respectively.2018, respectively, and $2.6 million for the year ended December 31, 2017.
The fair value of ESPP grants is measured at the date of grant using the Black-Scholes-MertonBlack-Scholes option-pricing model. Expected volatility wasis calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six-month vesting period.
The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions:
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Risk free interest rate | 2.3 | % | | 1.8 | % | | 0.9 | % |
| Dividend yield | 0.7 | % | | 0.4 | % | | 0.5 | % |
Volatility factor of the expected market price of the Company’s common stock | 56.6 | % | | 55.9 | % | | 62.5 | % |
| Expected life (in years) | 0.5 |
| | 0.5 |
| | 0.5 |
|
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Risk free interest rate | 0.4 | % | | 0.1 | % | | 0.1 | % |
| Dividend yield | 0.4 | % | | 0.2 | % | | 0.1 | % |
Volatility factor of the expected market price of the Company’s common stock | 95.0 | % | | 61.2 | % | | 33.0 | % |
| Expected life (in years) | 0.5 |
| | 0.5 |
| | 0.5 |
|
The Company expensed $2.0 million, $1.8 million, and $1.1 million for each of the years ended December 31, 2016, 2015,2019, and 2014,2018, respectively, and $1.0 million for the year ended December 31, 2017, based on the estimated fair value of the ESPP grants.
401(k) Plan
The Company has a defined contribution plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. For employees hired before December 31, 2014, the Company matches 100 percent of each employee’s contribution in cash on a dollar for dollar basis, up to six6 percent of the employee’s base salary and performance bonus, and may make additional contributions at its discretion. The Company matches 150 percent of contributions made by employees hired after December 31, 2014, up to nine6 percent of the employee’s base salary and performance bonus in lieu of pension plan benefits, and may make additional contributions at its discretion. Please refer to Note 8 -– Pension Benefits for additional discussion of pension benefits. The Company’s matching contributions to the 401(k) Plan were $5.4$5.1 million, $5.6$4.9 million, and $6.4$4.5 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively.
Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during each year were designated within a specific pool with key employees designated as participants that became entitled to payments under the Net Profits Plan after the Company has received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, 10 percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the 10 percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result, the 2007 pool was the last Net Profits Plan pool established by the Company.
The following table presents cash payments made or accrued under the Net Profits Plan related to periodic operations, of which the majority is recorded as general and administrative expense, and cash payments made or accrued as a result of divestitures of properties subject to the Net Profits Plan, which are recorded as a reduction to the net gain on divestiture activity line item in the accompanying statements of operations.
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Cash payments made or accrued related to operations | $ | 6,608 |
| | $ | 3,498 |
| | $ | 9,016 |
|
| Cash payments made or accrued related to divestitures | 24,349 |
| | 3,789 |
| | 8,341 |
|
| Total net settlements | $ | 30,957 |
| | $ | 7,287 |
| | $ | 17,357 |
|
Note 8 – Pension Benefits
The Company has a non-contributory defined benefit pension plan covering substantially all employees who meet age and service requirements and who began employment with the Company prior to January 1, 2016 (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of December 31, 2015.January 1, 2016. Employees participating in the Pension Plans as of December 31, 2015,prior to the plans being frozen will continue to earn benefits.
Obligations and Funded Status for the Pension Plans
The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to accumulatedwithin the other comprehensive loss,income (loss), net of tax.tax, line item in the accompanying statements of comprehensive income (loss). The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31.
|
| | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Change in benefit obligation: | | | |
| Projected benefit obligation at beginning of year | $ | 66,086 |
| | $ | 71,937 |
|
| Service cost | 5,582 |
| | 6,730 |
|
| Interest cost | 2,791 |
| | 2,622 |
|
| Actuarial (gain) loss | 2,035 |
| | (7,155 | ) |
| Benefits paid | (5,651 | ) | | (8,048 | ) |
| Projected benefit obligation at end of year | 70,843 |
| | 66,086 |
|
| | | | |
| Change in plan assets: | | | |
| Fair value of plan assets at beginning of year | 30,100 |
| | 30,978 |
|
| Actual return (loss) on plan assets | 3,985 |
| | (964 | ) |
| Employer contribution | 7,200 |
| | 8,134 |
|
| Benefits paid | (5,651 | ) | | (8,048 | ) |
| Fair value of plan assets at end of year | 35,634 |
| | 30,100 |
|
| Funded status at end of year | $ | (35,209 | ) | | $ | (35,986 | ) |
|
| | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 |
| | (in thousands) |
| Change in benefit obligation: | | | |
| Projected benefit obligation at beginning of year | $ | 62,547 |
| | $ | 57,867 |
|
| Service cost | 8,200 |
| | 7,949 |
|
| Interest cost | 2,908 |
| | 2,496 |
|
| Actuarial loss | 2,662 |
| | 2,397 |
|
| Benefits paid | (6,658 | ) | | (8,162 | ) |
| Projected benefit obligation at end of year | 69,659 |
| | 62,547 |
|
| | | | |
| Change in plan assets: | | | |
| Fair value of plan assets at beginning of year | 25,769 |
| | 27,940 |
|
| Actual return on plan assets | 1,575 |
| | (410 | ) |
| Employer contribution | 11,045 |
| | 6,401 |
|
| Benefits paid | (6,658 | ) | | (8,162 | ) |
| Fair value of plan assets at end of year | 31,731 |
| | 25,769 |
|
| Funded status at end of year | $ | (37,928 | ) | | $ | (36,778 | ) |
The Company’s underfunded status for the Pension Plans as of December 31, 2016,2019, and 2015, is $37.92018, was $35.2 million and $36.8$36.0 million, respectively, and is recognized in the accompanying balance sheets as a portion ofwithin the other noncurrent liabilities. No plan assets of the Qualified Pension Plan were returned to the Company during the year ended December 31, 2016.liabilities line item. There are no0 plan assets in the Nonqualified Pension Plan.
Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans
|
| | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Projected benefit obligation | $ | 70,843 |
| | $ | 66,086 |
|
| | | | |
| Accumulated benefit obligation | $ | 60,877 |
| | $ | 52,368 |
|
| Less: fair value of plan assets | (35,634 | ) | | (30,100 | ) |
| Underfunded accumulated benefit obligation | $ | 25,243 |
| | $ | 22,268 |
|
|
| | | | | | | |
| | As of December 31, |
| | 2016 | | 2015 |
| | (in thousands) |
| Projected benefit obligation | $ | 69,659 |
| | $ | 62,547 |
|
| | | | |
| Accumulated benefit obligation | $ | 54,681 |
| | $ | 46,439 |
|
| Less: Fair value of plan assets | (31,731 | ) | | (25,769 | ) |
| Underfunded accumulated benefit obligation | $ | 22,950 |
| | $ | 20,670 |
|
Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is
intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of the unrecognized net gain or loss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for athe year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan.
Pre-taxThe pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in the accumulated other comprehensive loss line item within the accompanying balance sheets as of December 31, 2019, and 2018, were as follows: |
| | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Unrecognized actuarial losses | $ | 14,406 |
| | $ | 15,741 |
|
| Unrecognized prior service costs | 31 |
| | 48 |
|
| Accumulated other comprehensive loss | $ | 14,437 |
| | $ | 15,789 |
|
The pension liability adjustments recognized in other comprehensive income (loss) during 2016, 2015,2019, 2018, and 2014,2017, were as follows:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands) |
| Net actuarial gain (loss) | $ | 377 |
| | $ | 4,329 |
| | $ | (2,995 | ) |
| Amortization of prior service cost | 17 |
| | 18 |
| | 17 |
|
| Amortization of net actuarial loss | 958 |
| | 1,327 |
| | 1,297 |
|
| Settlements | — |
| | — |
| | 3,009 |
|
| Total pension liability adjustment, pre-tax | 1,352 |
| | 5,674 |
| | 1,328 |
|
| Tax expense | (291 | ) | | (4,265 | ) | | (561 | ) |
Cumulative effect of accounting change (1) | — |
| | 2,969 |
| | — |
|
| Total pension liability adjustment, net | $ | 1,061 |
| | $ | 4,378 |
| | $ | 767 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Unrecognized actuarial losses | $ | 22,708 |
| | $ | 20,966 |
| | $ | 17,812 |
|
| Unrecognized prior service costs | 83 |
| | 101 |
| | 118 |
|
| Unrecognized transition obligation | — |
| | — |
| | — |
|
| Accumulated other comprehensive loss | $ | 22,791 |
| | $ | 21,067 |
| | $ | 17,930 |
|
The estimated net loss that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year is $1.6 million.
Pre-tax changes recognized in other comprehensive loss during 2016, 2015, and 2014, were as follows:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Net actuarial loss | $ | (3,322 | ) | | $ | (4,990 | ) | | $ | (10,062 | ) |
| Prior service cost | — |
| | — |
| | — |
|
| Less: | | | | | |
| Amortization of prior service cost | (16 | ) | | (17 | ) | | (17 | ) |
| Amortization of net actuarial loss | (1,582 | ) | | (1,486 | ) | | (689 | ) |
| Settlements | — |
| | (350 | ) | | — |
|
| Total other comprehensive loss | $ | (1,724 | ) | | $ | (3,137 | ) | | $ | (9,356 | ) |
| |
(1) | Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policiesand Statements of Stockholders’ Equity for additional information. |
Components of Net Periodic Benefit Cost for the Pension Plans
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands) |
| Components of net periodic benefit cost: | | | | | |
| Service cost | $ | 5,582 |
| | $ | 6,730 |
| | $ | 6,638 |
|
| Interest cost | 2,791 |
| | 2,622 |
| | 2,689 |
|
| Expected return on plan assets that reduces periodic pension benefit cost | (1,574 | ) | | (1,862 | ) | | (2,244 | ) |
| Amortization of prior service cost | 17 |
| | 18 |
| | 17 |
|
| Amortization of net actuarial loss | 958 |
| | 1,327 |
| | 1,297 |
|
| Settlements | — |
| | — |
| | 3,009 |
|
| Net periodic benefit cost | $ | 7,774 |
| | $ | 8,835 |
| | $ | 11,406 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Components of net periodic benefit cost: | | | | | |
| Service cost | $ | 8,200 |
| | $ | 7,949 |
| | $ | 6,335 |
|
| Interest cost | 2,908 |
| | 2,496 |
| | 2,191 |
|
| Expected return on plan assets that reduces periodic pension cost | (2,235 | ) | | (2,182 | ) | | (1,978 | ) |
| Amortization of prior service cost | 16 |
| | 17 |
| | 17 |
|
| Amortization of net actuarial loss | 1,582 |
| | 1,486 |
| | 689 |
|
| Settlements | — |
| | 350 |
| | — |
|
| Net periodic benefit cost | $ | 10,471 |
| | $ | 10,116 |
| | $ | 7,254 |
|
Pension Plan Assumptions
Weighted-averageThe weighted-average assumptions used to measure the Company’s projected benefit obligation andare as follows:
|
| | | |
| | As of December 31, |
| | 2019 | | 2018 |
| Projected benefit obligation: | | | |
| Discount rate | 3.6% | | 4.4% |
| Rate of compensation increase | 4.5% | | 6.2% |
The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows:
| | | | As of December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Projected benefit obligation | | | |
| Discount rate | 4.2% | | 4.7% | | 4.3% | |
| Rate of compensation increase | 6.2% | | 6.2% | | 6.2% | |
| Net periodic benefit cost | | |
| Net periodic benefit cost: | | |
| Discount rate | 4.7% | | 4.3% | | 5.0% | 4.4% | | 3.8% | | 4.2% |
Expected return on plan assets (1) | 7.5% | | 7.5% | | 7.5% | 5.0% | | 5.5% | | 6.5% |
| Rate of compensation increase | 6.2% | | 6.2% | | 6.2% | 6.2% | | 6.2% | | 6.2% |
| |
(1) | There is no0 assumed expected return on plan assets for the Nonqualified Pension Plan because there are no0 plan assets in the Nonqualified Pension Plan. |
The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy does not permitprohibits the direct investment of plan assets in the Company’s securities. The Qualified Pension Plan’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied.
The Qualified Pension Plan’s investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations.
The weighted-average asset allocation of the Qualified Pension Plan is as follows:
|
| | | | | | | | | |
| | | Target | | As of December 31, |
| Asset Category | | 2020 | | 2019 | | 2018 |
| Equity securities | | 35.0 | % | | 36.9 | % | | 31.8 | % |
| Fixed income securities | | 40.0 | % | | 38.1 | % | | 41.3 | % |
| Other securities | | 25.0 | % | | 25.0 | % | | 26.9 | % |
| Total | | 100.0 | % | | 100.0 | % | | 100.0 | % |
|
| | | | | | | | |
| | Target | | As of December 31, |
| Asset Category | 2017 | | 2016 | | 2015 |
| Equity securities | 35.0 | % | | 28.8 | % | | 39.1 | % |
| Fixed income securities | 43.0 | % | | 35.5 | % | | 34.0 | % |
| Other securities | 22.0 | % | | 35.7 | % | | 26.9 | % |
| Total | 100.0 | % | | 100.0 | % | | 100.0 | % |
There is no asset allocation of the Nonqualified Pension Plan since there are no0 plan assets in thatthe plan. An expected return on plan assets of 7.55.0 percent, 5.5 percent, and 6.5 percent was used to calculate the Company’s obligationnet periodic pension cost under the Qualified Pension Plan for 2016the years ended December 31, 2019, 2018, and 2015. Factors considered2017 respectively. The expected long-term rate of return assumption of the Qualified Pension Plan is based upon the target asset allocation and is determined using forward-looking assumptions in determiningthe context of historical returns and volatilities for each asset class, as well as correlations among asset classes. The Company evaluates the expected rate of return include the long-term historical rate of return provided by the equity and debt securities markets and input from the investment consultants and trustees managing theon plan assets. The difference in investment income using the projected rate of return compared to the actual rates of return for the past two years was not material and is not expected to have a material effectassets assumption on the accompanying statements of operations or cash flows from operating activities in future years.an annual basis.
Pension Plan Assets
The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2016,2019, and 2015,2018, utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements are as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | Fair Value Measurements Using: |
| | Actual Asset Allocation (1) | | Total | | Level 1 Inputs | | Level 2 Inputs | | Level 3 Inputs |
| | | | (in thousands) |
| As of December 31, 2019 | | | | | | | | | |
| Equity securities: | | | | | | | | | |
Domestic (2) | 17.3 | % | | $ | 6,176 |
| | $ | 4,130 |
| | $ | 2,046 |
| | $ | — |
|
International (3) | 19.6 | % | | 6,958 |
| | 6,958 |
| | — |
| | — |
|
| Total equity securities | 36.9 | % | | 13,134 |
| | 11,088 |
| | 2,046 |
| | — |
|
| Fixed income securities: | | | | | | | | | |
Core fixed income (4) | 31.4 | % | | 11,199 |
| | 11,199 |
| | — |
| | — |
|
Floating rate corporate loans (5) | 6.7 | % | | 2,379 |
| | 2,379 |
| | — |
| | — |
|
| Total fixed income securities | 38.1 | % | | 13,578 |
| | 13,578 |
| | — |
| | — |
|
| Other securities: | | | | | | | | | |
Real estate (6) | 5.4 | % | | 1,929 |
| | — |
| | — |
| | 1,929 |
|
Collective investment trusts (7) | 3.3 | % | | 1,168 |
| | — |
| | 1,168 |
| | — |
|
Hedge fund (8) | 16.3 | % | | 5,825 |
| | 2,006 |
| | — |
| | 3,819 |
|
| Total other securities | 25.0 | % | | 8,922 |
| | 2,006 |
| | 1,168 |
| | 5,748 |
|
| Total investments | 100.0 | % | | $ | 35,634 |
| | $ | 26,672 |
| | $ | 3,214 |
| | $ | 5,748 |
|
| | | | | | | | | | |
| As of December 31, 2018 | | | | | | | | | |
| Equity securities: | | | | | | | | | |
Domestic (2) | 15.4 | % | | $ | 4,639 |
| | $ | 3,197 |
| | $ | 1,442 |
| | $ | — |
|
International (3) | 16.4 | % | | 4,941 |
| | 3,642 |
| | 1,299 |
| | — |
|
| Total equity securities | 31.8 | % | | 9,580 |
| | 6,839 |
| | 2,741 |
| | — |
|
| Fixed income securities: | | | | | | | | | |
Core fixed income (4) | 34.4 | % | | 10,342 |
| | 10,342 |
| | — |
| | — |
|
Floating rate corporate loans (5) | 6.9 | % | | 2,078 |
| | 2,078 |
| | — |
| | — |
|
| Total fixed income securities | 41.3 | % | | 12,420 |
| | 12,420 |
| | — |
| | — |
|
| Other securities: | | | | | | | | | |
Real estate (6) | 6.0 | % | | 1,820 |
| | — |
| | — |
| | 1,820 |
|
Collective investment trusts (7) | 3.1 | % | | 934 |
| | — |
| | 934 |
| | — |
|
Hedge fund (8) | 17.8 | % | | 5,346 |
| | — |
| | 1,659 |
| | 3,687 |
|
| Total other securities | 26.9 | % | | 8,100 |
| | — |
| | 2,593 |
| | 5,507 |
|
| Total investments | 100.0 | % | | $ | 30,100 |
| | $ | 19,259 |
| | $ | 5,334 |
| | $ | 5,507 |
|
|
| | | | | | | | | | | | | | | | | | |
| | | | | | Fair Value Measurements Using: |
| | Actual Asset Allocation | | Total | | Level 1 Inputs | | Level 2 Inputs | | Level 3 Inputs |
| | | | (in thousands) |
| As of December 31, 2016 | | | | | | | | | |
| Cash | — | % | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Equity Securities: |
|
| |
|
| |
|
| |
|
| |
|
|
Domestic (1) | 18.7 | % | | 5,945 |
| | 4,471 |
| | 1,474 |
| | — |
|
International (2) | 10.1 | % | | 3,192 |
| | 3,192 |
| | — |
| | — |
|
| Total Equity Securities | 28.8 | % | | 9,137 |
| | 7,663 |
| | 1,474 |
| | — |
|
| Fixed Income Securities: |
|
| |
|
| |
|
| |
|
| | |
High-Yield Bonds (3) | 2.6 | % | | 822 |
| | 822 |
| | — |
| | — |
|
Core Fixed Income (4) | 25.0 | % | | 7,923 |
| | 7,923 |
| | — |
| | — |
|
Floating Rate Corp Loans (5) | 7.9 | % | | 2,495 |
| | 2,495 |
| | — |
| | — |
|
| Total Fixed Income Securities | 35.5 | % | | 11,240 |
| | 11,240 |
| | — |
| | — |
|
| Other Securities: |
|
| |
|
| |
|
| |
|
| |
|
|
Commodities (6) | 1.8 | % | | 578 |
| | 578 |
| | — |
| | — |
|
Real Estate (7) | 5.1 | % | | 1,629 |
| | — |
| | — |
| | 1,629 |
|
Collective Investment Trusts (8) | 17.5 | % | | 5,562 |
| | — |
| | 5,562 |
| | — |
|
Hedge Fund (9) | 11.3 | % | | 3,585 |
| | — |
| | — |
| | 3,585 |
|
| Total Other Securities | 35.7 | % | | 11,354 |
| | 578 |
| | 5,562 |
| | 5,214 |
|
| Total Investments | 100.0 | % | | $ | 31,731 |
| | $ | 19,481 |
| | $ | 7,036 |
| | $ | 5,214 |
|
| | | | | | | | | | |
| As of December 31, 2015 | | | | | | | | | |
| Cash | — | % | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Equity Securities: | | | | | | | | | |
Domestic (1) | 26.1 | % | | 6,729 |
| | 4,943 |
| | 1,786 |
| | — |
|
International (2) | 13.0 | % | | 3,353 |
| | 3,353 |
| | — |
| | — |
|
| Total Equity Securities | 39.1 | % | | 10,082 |
| | 8,296 |
| | 1,786 |
| | — |
|
| Fixed Income Securities: | | | | | | | | | |
High-Yield Bonds (3) | 2.8 | % | | 722 |
| | 722 |
| | — |
| | — |
|
Core Fixed Income (4) | 22.5 | % | | 5,789 |
| | 5,789 |
| | — |
| | — |
|
Floating Rate Corp Loans (5) | 8.7 | % | | 2,247 |
| | 2,247 |
| | — |
| | — |
|
| Total Fixed Income Securities | 34.0 | % | | 8,758 |
| | 8,758 |
| | — |
| | — |
|
| Other Securities: | | | | | | | | | |
Commodities (6) | 2.7 | % | | 700 |
| | 700 |
| | — |
| | — |
|
Real Estate (7) | 5.8 | % | | 1,499 |
| | — |
| | — |
| | 1,499 |
|
Collective Investment Trusts (8) | 4.6 | % | | 1,184 |
| | — |
| | 1,184 |
| | — |
|
Hedge Fund (9) | 13.8 | % | | 3,546 |
| | — |
| | — |
| | 3,546 |
|
| Total Other Securities | 26.9 | % | | 6,929 |
| | 700 |
| | 1,184 |
| | 5,045 |
|
| Total Investments | 100.0 | % | | $ | 25,769 |
| | $ | 17,754 |
| | $ | 2,970 |
| | $ | 5,045 |
|
| |
(1) | Percentages may not calculate due to rounding. |
| |
(2) | Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of this fundthese funds is to approximate the S&P 500 by investing in one or more collective investment funds. |
| |
(2)(3)
| International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations. |
| |
(3)
| High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. |
| |
(4) | The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. |
| |
(5) | Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. |
| |
(6) | Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. |
| |
(7)
| The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. |
| |
(8)(7)
| Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. |
| |
(9)(8)
| The hedge fund portfolio includes an investmentinvestments in an actively traded global mutual fundfunds that focusesfocus on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. |
Included below is a summary of the changes in Level 3 plan assets (in thousands):
|
| | | |
| Balance at January 1, 2018 | $ | 5,209 |
|
| Purchases | — |
|
| Realized gain on assets | 191 |
|
| Unrealized gain on assets | 152 |
|
| Disposition | (45 | ) |
| Balance at December 31, 2018 | $ | 5,507 |
|
| Purchases | — |
|
| Realized gain on assets | 190 |
|
| Unrealized gain on assets | 51 |
|
| Disposition | — |
|
| Balance at December 31, 2019 | $ | 5,748 |
|
|
| | | |
| Balance at January 1, 2015 | $ | 4,864 |
|
| Purchases | — |
|
| Realized gain on assets | 165 |
|
| Unrealized gain on assets | 16 |
|
| Balance at December 31, 2015 | $ | 5,045 |
|
| Purchases | 561 |
|
| Realized gain on assets | 54 |
|
| Unrealized gain on assets | 115 |
|
| Disposition | (561 | ) |
| Balance at December 31, 2016 | $ | 5,214 |
|
Contributions
The Company contributed $11.0$7.2 million, $6.4$8.1 million, and $5.3$7.0 million to the Pension Plans infor the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively. The Company expects to make a $7.8$5.6 million contribution to the Pension Plans in 2017.
2020.
Benefit Payments
The Pension Plans made actual benefit payments of $6.7$5.7 million, $8.2$8.0 million, and $2.8$10.8 million in the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively. Expected benefit payments over the next 10 years are as follows:
|
| | | |
| Years Ending December 31, | (in thousands) |
| 2020 | $ | 7,609 |
|
| 2021 | $ | 3,914 |
|
| 2022 | $ | 4,022 |
|
| 2023 | $ | 6,308 |
|
| 2024 | $ | 4,939 |
|
| 2025 through 2029 | $ | 25,065 |
|
|
| | | | |
| Years Ending December 31, | | (in thousands) |
| 2017 | | $ | 6,532 |
|
| 2018 | | $ | 3,256 |
|
| 2019 | | $ | 4,480 |
|
| 2020 | | $ | 4,778 |
|
| 2021 | | $ | 5,772 |
|
| 2022 through 2026 | | $ | 38,708 |
|
Note 9 - Earnings Per Share
Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method.
PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from 0 to 2 times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Asset Retirement ObligationsCompensation Plans under the heading Performance Share Units.
On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal amount of the Senior Convertible Notes in cash and the excess
conversion value in shares. However, the Company has not made an irrevocable election and thereby reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business circumstances warrant. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the years ended December 31, 2019, 2018, and 2017, therefore, the Senior Convertible Notes had no dilutive impact. In connection with the offering of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters that would effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions will always be anti-dilutive and therefore will never be reflected in diluted net income or loss per share. Please refer to Asset Retirement Obligations in Note 15 – SummaryLong-Term Debt for additional discussion.
When the Company recognizes a net loss from continuing operations, as was the case for the years ended December 31, 2019, and 2017, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of Significant Accounting Policies diluted net loss per common share.
The following table details the weighted-average anti-dilutive securities for a discussionthe years presented: |
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands) |
| Anti-dilutive | 684 |
| | — |
| | 264 |
|
The following table sets forth the calculations of the initialbasic and subsequent measurements of asset retirement obligation liabilities and the significant assumptions used in the estimates.diluted net income (loss) per common share: |
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands, except per share data) |
| Net income (loss) | $ | (187,001 | ) | | $ | 508,407 |
| | $ | (160,843 | ) |
| | | | | | |
| Basic weighted-average common shares outstanding | 112,544 |
| | 111,912 |
| | 111,428 |
|
| Dilutive effect of non-vested RSUs and contingent PSUs | — |
| | 1,590 |
| | — |
|
| Diluted weighted-average common shares outstanding | 112,544 |
| | 113,502 |
| | 111,428 |
|
| | | | | | |
| Basic net income (loss) per common share | $ | (1.66 | ) | | $ | 4.54 |
| | $ | (1.44 | ) |
| Diluted net income (loss) per common share | $ | (1.66 | ) | | $ | 4.48 |
| | $ | (1.44 | ) |
A reconciliation of the Company’s total asset retirement obligation liability is as follows:
|
| | | | | | | |
| | As of December 31, |
| | 2016 | | 2015 |
| | (in thousands) |
| Beginning asset retirement obligation | $ | 140,874 |
| | $ | 122,124 |
|
Liabilities incurred (1) | 21,293 |
| | 14,471 |
|
Liabilities settled (2) | (57,100 | ) | | (24,781 | ) |
| Accretion expense | 7,795 |
| | 5,091 |
|
| Revision to estimated cash flows | 10,445 |
| | 23,969 |
|
Ending asset retirement obligation (3)(4) | $ | 123,307 |
| | $ | 140,874 |
|
| |
(1)
| Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. |
| |
(2)
| Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. |
| |
(3)
| Balance as of December 31, 2016, included $26.2 million of asset retirement obligations associated with oil and gas properties held for sale, specifically the Company’s outside-operated Eagle Ford shale assets. There were no material asset retirement obligations related to assets held for sale as of December 31, 2015.
|
| |
(4)
| Balances as of December 31, 2016, and 2015, included $932,000 and $3.3 million, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in accounts payable and accrued expenses on the accompanying balance sheets. |
Note 10 – Derivative Financial Instruments
Summary of Oil, Gas, and NGL Derivative Contracts in Place
The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of December 31, 2016,2019, all derivative counterparties were members of the Company’s credit facilityCredit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and gas production, and NGLs.swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.
The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices.
As of December 31, 2016,2019, the Company had commodity derivative contracts outstanding through the secondfourth quarter of 2020 for a total of 11.3 million Bbls of oil production, 137.2 million MMBtu of net gas production, and 13.4 million Bbls of NGL production,2022, as summarized in the tables below.
Oil Swaps
|
| | | | | | | |
| Contract Period | | NYMEX WTI Volumes | | Weighted- Average Contract Price |
| | | (MBbls) | | (per Bbl) |
| First quarter 2017 | | 1,574 |
| | $ | 46.41 |
|
| Second quarter 2017 | | 1,444 |
| | $ | 46.44 |
|
| Third quarter 2017 | | 1,340 |
| | $ | 46.66 |
|
| Fourth quarter 2017 | | 1,254 |
| | $ | 46.35 |
|
| Total | | 5,612 |
| | |
|
| | | | | | | |
| Contract Period | | NYMEX WTI Volumes | | Weighted-Average Contract Price |
| | | (MBbl) | | (per Bbl) |
| First quarter 2020 | | 2,486 |
| | $ | 59.65 |
|
| Second quarter 2020 | | 2,838 |
| | $ | 58.81 |
|
| Third quarter 2020 | | 3,361 |
| | $ | 56.43 |
|
| Fourth quarter 2020 | | 3,937 |
| | $ | 56.94 |
|
| 2021 | | 667 |
| | $ | 56.00 |
|
| Total | | 13,289 |
| | |
Oil Collars
|
| | | | | | | | | | | |
| Contract Period | | NYMEX WTI Volumes | | Weighted- Average Floor Price | | Weighted- Average Ceiling Price |
| | | (MBbls) | | (per Bbl) | | (per Bbl) |
| First quarter 2017 | | 704 |
| | $ | 45.00 |
| | $ | 54.17 |
|
| Second quarter 2017 | | 636 |
| | $ | 45.00 |
| | $ | 54.10 |
|
| Third quarter 2017 | | 583 |
| | $ | 45.00 |
| | $ | 54.05 |
|
| Fourth quarter 2017 | | 540 |
| | $ | 45.00 |
| | $ | 54.01 |
|
| 2018 | | 2,312 |
| | $ | 50.00 |
| | $ | 59.24 |
|
| 2019 | | 943 |
| | $ | 50.00 |
| | $ | 61.15 |
|
| Total | | 5,718 |
| | | | |
|
| | | | | | | | | | | |
| Contract Period | | NYMEX WTI Volumes | | Weighted-Average Floor Price | | Weighted-Average Ceiling Price |
| | | (MBbl) | | (per Bbl) | | (per Bbl) |
| First quarter 2020 | | 2,267 |
| | $ | 55.00 |
| | $ | 63.91 |
|
| Second quarter 2020 | | 1,881 |
| | $ | 55.00 |
| | $ | 62.17 |
|
| Third quarter 2020 | | 1,252 |
| | $ | 55.00 |
| | $ | 62.90 |
|
| Fourth quarter 2020 | | 610 |
| | $ | 55.00 |
| | $ | 61.90 |
|
| 2021 | | 329 |
| | $ | 55.00 |
| | $ | 56.70 |
|
| Total | | 6,339 |
| | | | |
Natural GasOil Basis Swaps
|
| | | | | | | | | | | | | | | | | |
| Contract Period | | Sold Volumes | | Weighted- Average Contract Price | | Purchased Volumes (1) | | Weighted- Average Contract Price | | Net Volumes |
| | | (BBtu) | | (per MMBtu) | | (BBtu) | | (per MMBtu) | | (BBtu) |
| First quarter 2017 | | 29,420 |
| | $ | 3.76 |
| | — |
| | $ | — |
| | 29,420 |
|
| Second quarter 2017 | | 26,205 |
| | $ | 3.98 |
| | — |
| | $ | — |
| | 26,205 |
|
| Third quarter 2017 | | 23,657 |
| | $ | 4.01 |
| | — |
| | $ | — |
| | 23,657 |
|
| Fourth quarter 2017 | | 22,001 |
| | $ | 3.98 |
| | — |
| | $ | — |
| | 22,001 |
|
| 2018 | | 63,166 |
| | $ | 3.68 |
| | (30,606 | ) | | $ | 4.27 |
| | 32,560 |
|
| 2019 | | 27,743 |
| | $ | 4.20 |
| | (24,415 | ) | | $ | 4.34 |
| | 3,328 |
|
Total (2) | | 192,192 |
| | | | (55,021 | ) | | | | 137,171 |
|
|
| | | | | | | | | | | | | | |
| Contract Period | | WTI Midland-NYMEX WTI Volumes | | Weighted-Average Contract Price (1) | | NYMEX WTI-ICE Brent Volumes | | Weighted-Average Contract Price (2) |
| | | (MBbl) | | (per Bbl) | | (MBbl) | | (per Bbl) |
| First quarter 2020 | | 4,193 |
| | $ | (0.68 | ) | | — |
| | $ | — |
|
| Second quarter 2020 | | 3,495 |
| | $ | (0.68 | ) | | 910 |
| | $ | (8.06 | ) |
| Third quarter 2020 | | 3,325 |
| | $ | (0.74 | ) | | 920 |
| | $ | (8.01 | ) |
| Fourth quarter 2020 | | 3,261 |
| | $ | (0.73 | ) | | 920 |
| | $ | (8.01 | ) |
| 2021 | | 5,954 |
| | $ | 0.59 |
| | 3,650 |
| | $ | (7.86 | ) |
| 2022 | | — |
| | $ | — |
| | 3,650 |
| | $ | (7.78 | ) |
| Total | | 20,228 |
| | | | 10,050 |
| | |
| |
(1) | During 2016,Represents the Company restructured certain of its gas derivative contracts by buying fixed price volumes to offset existing 2018differential between WTI Midland (Midland, Texas) and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No cash or other consideration was included as part of the restructuring.NYMEX WTI (Cushing, Oklahoma). |
| |
(2) | Total net volumes ofRepresents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea). |
Gas Swaps
|
| | | | | | | | | | | | | | |
| Contract Period | | IF HSC Volumes | | Weighted-Average Contract Price | | WAHA Volumes | | Weighted-Average Contract Price |
| | | (BBtu) | | (per MMBtu) | | (BBtu) | | (per MMBtu) |
| First quarter 2020 | | 9,123 |
| | $ | 2.98 |
| | 3,099 |
| | $ | 1.93 |
|
| Second quarter 2020 | | 4,160 |
| | $ | 2.20 |
| | 3,196 |
| | $ | 0.56 |
|
| Third quarter 2020 | | 4,493 |
| | $ | 2.41 |
| | 3,268 |
| | $ | 1.03 |
|
| Fourth quarter 2020 | | 3,722 |
| | $ | 2.36 |
| | 3,419 |
| | $ | 1.17 |
|
| 2021 | | — |
| | $ | — |
| | 4,224 |
| | $ | 1.51 |
|
Total (1) | | 21,498 |
| | | | 17,206 |
| | |
| |
(1) | The Company has natural gas swaps arein place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of December 31, 2019, WAHA volumes were comprised of 92 percent IF El Paso Permian (3%), IF HSC (94%),WAHA and IF NNG Ventura (3%).8 percent GD WAHA. |
NGL Swaps
|
| | | | | | | | | | | | | | |
| | | OPIS Ethane Purity Mont Belvieu | | OPIS Propane Mont Belvieu Non-TET |
| Contract Period | | Volumes | | Weighted-Average Contract Price | | Volumes | | Weighted-Average Contract Price |
| | | (MBbl) | | (per Bbl) | | (MBbl) | | (per Bbl) |
| First quarter 2020 | | 447 |
| | $ | 11.53 |
| | 382 |
| | $ | 22.64 |
|
| Second quarter 2020 | | 264 |
| | $ | 11.13 |
| | 382 |
| | $ | 22.34 |
|
| Third quarter 2020 | | — |
| | $ | — |
| | 409 |
| | $ | 22.33 |
|
| Fourth quarter 2020 | | — |
| | $ | — |
| | 466 |
| | $ | 22.29 |
|
| Total | | 711 |
| | | | 1,639 |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | OPIS Purity Ethane Mont Belvieu | | OPIS Propane Mont Belvieu Non-TET | | OPIS Normal Butane Mont Belvieu Non-TET | | OPIS Isobutane Mont Belvieu Non-TET | | OPIS Natural Gasoline Mont Belvieu Non-TET |
| Contract Period | | Volumes | Weighted-Average Contract Price | | Volumes | Weighted-Average
Contract Price | | Volumes | Weighted-Average
Contract Price | | Volumes | Weighted-Average
Contract Price | | Volumes | Weighted-Average
Contract Price |
| | | (MBbls) | (per Bbl) | | (MBbls) | (per Bbl) | | (MBbls) | (per Bbl) | | (MBbls) | (per Bbl) | | (MBbls) | (per Bbl) |
| First quarter 2017 | | 847 |
| $ | 8.63 |
| | 692 |
| $ | 21.90 |
| | 122 |
| $ | 30.69 |
| | 94 |
| $ | 31.12 |
| | 156 |
| $ | 47.54 |
|
| Second quarter 2017 | | 787 |
| $ | 8.86 |
| | 634 |
| $ | 21.90 |
| | 112 |
| $ | 30.69 |
| | 86 |
| $ | 31.12 |
| | 143 |
| $ | 47.56 |
|
| Third quarter 2017 | | 736 |
| $ | 9.14 |
| | 588 |
| $ | 21.91 |
| | 104 |
| $ | 30.70 |
| | 80 |
| $ | 31.12 |
| | 133 |
| $ | 47.59 |
|
| Fourth quarter 2017 | | 692 |
| $ | 9.10 |
| | 550 |
| $ | 21.91 |
| | 98 |
| $ | 30.70 |
| | 74 |
| $ | 31.12 |
| | 124 |
| $ | 47.61 |
|
| 2018 | | 2,434 |
| $ | 10.18 |
| | 1,442 |
| $ | 22.86 |
| | — |
| $ | — |
| | — |
| $ | — |
| | — |
| $ | — |
|
| 2019 | | 2,176 |
| $ | 11.95 |
| | — |
| $ | — |
| | — |
| $ | — |
| | — |
| $ | — |
| | — |
| $ | — |
|
| 2020 | | 539 |
| $ | 11.13 |
| | — |
| $ | — |
| | — |
| $ | — |
| | — |
| $ | — |
| | — |
| $ | — |
|
| Total | | 8,211 |
| | | 3,906 |
| | | 436 |
| | | 334 |
| | | 556 |
| |
Commodity Derivative Contracts Entered Into After December 31, 2016
Subsequent to December 31, 2016, and pursuant to a definitive agreement, the Company entered into certain NYMEX swap contracts on behalf of the buyer of its outside-operated Eagle Ford shale assets, which will be novated to the buyer at closing expected to occur in the first quarter of 2017. Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale.2019
Additionally, subsequentSubsequent to December 31, 2016,2019, the Company entered into variousthe following commodity derivative contracts:
fixed price NYMEX WTI oil swap contracts as summarized below:for the fourth quarter of 2020 through January 2021 for a total of 0.6 MMBbl of oil production at a weighted-average contract price of $57.82 per Bbl; and
derivative costless collarfixed price WTI Midland-NYMEX WTI oil basis swap contracts for the second quarter of 2020 through the fourth quarter of 20192022 for a total of 2.7 million Bbls of oil production with contract floor prices of $50.00 per Bbl and contract ceiling prices ranging from $57.00 per Bbl to $58.40 per Bbl;
derivative fixed price Midland-Cushing basis swap contracts through the fourth quarter of 2019 for a total of 3.7 million Bbls16.3 MMBbl of oil production at a weighted-average contract prices ranging from ($1.23) per Bbl to ($1.45) per Bbl; and
derivative fixed price swap contracts through the first quarter of 2018 for a total of 1.1 million Bbls of NGL production at contract prices ranging from $35.07 per Bbl to $49.88$1.14 per Bbl.
Derivative Assets and Liabilities Fair Value
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities.liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the commodity derivative contracts at December 31, 2019, and 2018, was a net liability of $91.7 million at December 31, 2016, and net asset of $488.4$21.5 million at December 31, 2015.and $158.3 million, respectively.
The following tables detailtable details the fair value of derivativescommodity derivative contracts recorded in the accompanying balance sheets, by category: |
| | | | | | | | | | | |
| | As of December 31, 2016 |
| | Derivative Assets | | Derivative Liabilities |
| | Balance Sheet Classification | | Fair Value | | Balance Sheet Classification | | Fair Value |
| | (in thousands) |
| Commodity contracts | Current assets | | $ | 54,521 |
| | Current liabilities | | $ | 115,464 |
|
| Commodity contracts | Noncurrent assets | | 67,575 |
| | Noncurrent liabilities | | 98,340 |
|
| Derivatives not designated as hedging instruments | | | $ | 122,096 |
| | | | $ | 213,804 |
|
|
| | | | | | | |
| | As of December 31, 2019 | | As of December 31, 2018 |
| | (in thousands) |
| Derivative assets: | | | |
| Current assets | $ | 55,184 |
| | $ | 175,130 |
|
| Noncurrent assets | 20,624 |
| | 58,499 |
|
| Total derivative assets | $ | 75,808 |
| | $ | 233,629 |
|
| Derivative liabilities: | | | |
| Current liabilities | $ | 50,846 |
| | $ | 62,853 |
|
| Noncurrent liabilities | 3,444 |
| | 12,496 |
|
| Total derivative liabilities | $ | 54,290 |
| | $ | 75,349 |
|
|
| | | | | | | | | | | |
| | As of December 31, 2015 |
| | Derivative Assets | | Derivative Liabilities |
| | Balance Sheet Classification | | Fair Value | | Balance Sheet Classification | | Fair Value |
| | (in thousands) |
| Commodity contracts | Current assets | | $ | 367,710 |
| | Current liabilities | | $ | 8 |
|
| Commodity contracts | Noncurrent assets | | 120,701 |
| | Noncurrent liabilities | | — |
|
| Derivatives not designated as hedging instruments | | | $ | 488,411 |
| | | | $ | 8 |
|
Offsetting of Derivative Assets and Liabilities
As of December 31, 2016,2019, and 2015,2018, all derivative instruments held by the Company were subject to master netting arrangements bywith various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.
The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts: |
| | | | | | | | | | | | | | | | |
| | | Derivative Assets | | Derivative Liabilities |
| | | As of December 31, | | As of December 31, |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| | | (in thousands) |
| Gross amounts presented in the accompanying balance sheets | | $ | 75,808 |
| | $ | 233,629 |
| | $ | (54,290 | ) | | $ | (75,349 | ) |
| Amounts not offset in the accompanying balance sheets | | (35,075 | ) | | (56,041 | ) | | 35,075 |
| | 56,041 |
|
| Net amounts | | $ | 40,733 |
| | $ | 177,588 |
| | $ | (19,215 | ) | | $ | (19,308 | ) |
|
| | | | | | | | | | | | | | | | |
| | | Derivative Assets | | Derivative Liabilities |
| | | As of December 31, | | As of December 31, |
| Offsetting of Derivative Assets and Liabilities | | 2016 | | 2015 | | 2016 | | 2015 |
| | | (in thousands) |
| Gross amounts presented in the accompanying balance sheets | | $ | 122,096 |
| | $ | 488,411 |
| | $ | (213,804 | ) | | $ | (8 | ) |
| Amounts not offset in the accompanying balance sheets | | (118,080 | ) | | (8 | ) | | 118,080 |
| | 8 |
|
| Net amounts | | $ | 4,016 |
| | $ | 488,403 |
| | $ | (95,724 | ) | | $ | — |
|
The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive loss.income (loss). The Company had no0 derivatives designated as hedging instruments for the years ended December 31, 2016, 2015,2019, 2018, and 2014.2017. Please refer to Note 11 -– Fair Value Measurements for more information regarding the Company’s derivative instruments, including its valuation techniques.
The following table summarizes the commodity components of the net derivative (gain) loss line item presented in the accompanying statements of operations:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands) |
| Derivative settlement (gain) loss: | | | | | |
| Oil contracts | $ | 19,685 |
| | $ | 68,860 |
| | $ | 31,176 |
|
| Gas contracts | (23,008 | ) | | 13,029 |
| | (87,857 | ) |
| NGL contracts | (35,899 | ) | | 53,914 |
| | 35,447 |
|
| Total derivative settlement (gain) loss | $ | (39,222 | ) | | $ | 135,803 |
| | $ | (21,234 | ) |
| | | | | | |
| Net derivative (gain) loss: | | | | | |
| Oil contracts | $ | 172,055 |
| | $ | (192,002 | ) | | $ | 71,502 |
|
| Gas contracts | (41,205 | ) | | 35,411 |
| | (76,315 | ) |
| NGL contracts | (33,311 | ) | | (5,241 | ) | | 31,227 |
|
| Total net derivative (gain) loss | $ | 97,539 |
| | $ | (161,832 | ) | | $ | 26,414 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Derivative settlement (gain) loss: | | | | | |
| Oil contracts | $ | (243,102 | ) | | $ | (362,219 | ) | | $ | (28,410 | ) |
Gas contracts (1) | (94,936 | ) | | (123,180 | ) | | 26,706 |
|
| NGL contracts | 8,560 |
| | (27,167 | ) | | (10,911 | ) |
| Total derivative settlement gain | $ | (329,478 | ) | | $ | (512,566 | ) | | $ | (12,615 | ) |
| | | | | | |
| Total derivative (gain) loss: | | | | | |
| Oil contracts | $ | 85,370 |
| | $ | (191,165 | ) | | $ | (457,082 | ) |
| Gas contracts | 81,060 |
| | (189,734 | ) | | (93,267 | ) |
| NGL contracts | 84,203 |
| | (27,932 | ) | | (32,915 | ) |
| Total net derivative (gain) loss | $ | 250,633 |
| | $ | (408,831 | ) | | $ | (583,264 | ) |
| |
(1)
| Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region. |
Credit Related Contingent Features
As of December 31, 2016,2019, and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facilityCredit Agreement lender group. The Company’s obligations under itsUnder the Credit Agreement, and derivative contracts are secured by mortgagesthe Company is required to provide mortgage liens on assets having a value equal to at least 9085 percent of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.
Note 11 – Fair Value Measurements
The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
Level 1 – quoted prices in active markets for identical assets or liabilities
Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3 – significant inputs to the valuation model are unobservable
The following table is a listing
Please refer to Note 1 – Summary of Significant Accounting Policiesfor additional information on the Company’s assets and liabilities that are measured atpolicies for determining fair value infor the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2016:
|
| | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 |
| | (in thousands) |
| Assets: | | | | | |
Derivatives (1) | $ | — |
| | $ | 122,096 |
| | $ | — |
|
Total property and equipment, net (2) | $ | — |
| | $ | — |
| | $ | 88,205 |
|
| Liabilities: | | | | | |
Derivatives (1) | $ | — |
| | $ | 213,804 |
| | $ | — |
|
Net Profits Plan (1) | $ | — |
| | $ | — |
| | $ | 411 |
|
| |
(1)
| This represents a financial asset or liability that is measured at fair value on a recurring basis. |
| |
(2)
| This represents a non-financial asset that is measured at fair value on a nonrecurring basis. |
categories discussed below.
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2015:
2019:
| | | | Level 1 | | Level 2 | | Level 3 | Level 1 | | Level 2 | | Level 3 |
| | (in thousands) | (in thousands) |
| Assets: | | | | | | | | | | |
Derivatives (1) | $ | — |
| | $ | 488,411 |
| | $ | — |
| $ | — |
| | $ | 75,808 |
| | $ | — |
|
Total property and equipment, net (2) | $ | — |
| | $ | — |
| | $ | 124,813 |
| |
| Liabilities: | | | | | | | | | | |
Derivatives (1) | $ | — |
| | $ | 8 |
| | $ | — |
| $ | — |
| | $ | 54,290 |
| | $ | — |
|
Net Profits Plan (1) | $ | — |
| | $ | — |
| | $ | 7,611 |
| |
| |
(1) | This represents a financial asset or liability that is measured at fair value on a recurring basis. |
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2018:
|
| | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 |
| | (in thousands) |
| Assets: | | | | | |
Derivatives (1) | $ | — |
| | $ | 233,629 |
| | $ | — |
|
| Liabilities: | | | | | |
Derivatives (1) | $ | — |
| | $ | 75,349 |
| | $ | — |
|
| |
(2)(1)
| This represents a non-financialfinancial asset or liability that is measured at fair value on a nonrecurringrecurring basis. |
Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-priceexit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.
Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. All of the Company’s derivative counterparties are members of the Company’s credit facility lender group.
Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date.
The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and with other marketplace participants, the Company recognizes that third partiesthird-parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.
Refer to Note 10 -– Derivative Financial Instrumentsfor more information regarding the Company’s derivative instruments.
Proved and Unproved Oil and Gas Properties and Other Property and Equipment
Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication thethat associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique which converts future cash flow amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. The calculation of the discount rates is based on the best information available and the rates used ranged from 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of December 31, 2016, and 2015. The Company believes the discount rates are representative of current market conditions and consider estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates.
The following table presents impairment of proved properties expense recorded for the periods presented: |
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Impairment of proved properties | $ | 354.6 |
| | $ | 468.7 |
| | $ | 84.5 |
|
Impairments of proved properties during the year ended December 31, 2016, related primarily to the decline in expected reserve cash flows for the Company’s outside-operated Eagle Ford shale assets driven by commodity price declines during the first quarter of 2016, and downward performance reserve revisions in the fourth quarter of 2016 for the Company’s
Powder River Basin assets. Impairments of proved properties during the year ended December 31, 2015, were due to the decline in expected reserve cash flows driven by commodity price declines and were recorded mainly in the Company’s east Texas and Powder River Basin programs with smaller impacts on other legacy and non-core assets in the Rocky Mountain region. Impairments of proved properties during the year ended December 31, 2014, resulted from the significant decline in commodity prices in late 2014 and recognition of the outcomes of exploration and delineation wells in certain prospects in the Company’s South Texas & Gulf Coast and Permian regions.
Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.
There were 0 proved or unproved oil and gas properties recorded at fair value on the accompanying balance sheets as of December 31, 2019, or December 31, 2018.
The following table presents
impairment of proved properties expense and abandonment and impairment of unproved properties expense recorded for the periods presented:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in millions) |
| Abandonment and impairment of unproved properties | $ | 80.4 |
| | $ | 78.6 |
| | $ | 75.6 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in millions) |
| Impairment of proved properties | $ | — |
| | $ | — |
| | $ | 3.8 |
|
| Abandonment and impairment of unproved properties | 33.8 |
| | 49.9 |
| | 12.3 |
|
| Impairment of oil and gas properties | $ | 33.8 |
| | $ | 49.9 |
| | $ | 16.1 |
|
Abandonment and impairment of unproved properties expense recorded during the yearyears ended December 31, 2016,2019, 2018, and 2017 primarily related primarily to a decrease in the fair value of the Company’s unproved Powder River Basin propertiesactual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to downward performance reserve revisions and lower market prices based on recent third-party acreage transactions. In all other periods, abandonment and impairment expense resulted from lease expirations and acreage the Company no longer intended to develop in light oftitle defects, changes in drillingdevelopment plans, in response to the decline in commodity prices.
Other property and equipment. Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. During the year ended December 31, 2015, the Company recorded impairment of other property and equipment expense of $49.4 million on the Company’s gathering system assets in its east Texas program. These assets were impaired in conjunction with the impairment of the associated proved and unproved properties, which the Company did not intend to develop and subsequently sold. There were no other property and equipment impairments in 2016 or 2014.
Oil and gas properties held for sale. Proved and unproved oil and gas properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various income valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain on divestiture activity line item in the accompanying statements of operations. There wereno assets held for sale recorded at fair value as of December 31, 2016, or 2015, as the carrying values were below the estimated fair values less costs to sell. Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale for additional discussion.
Acquisitions of proved and unproved properties. Assets acquired and liabilities assumed under transactions that meet the criteria of a business combination under ASC Topic 805, Business Combinations are recorded at fair value on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. The Rock Oil Acquisition closed on October 4, 2016, and therefore, was not recorded at fair value as of December 31. 2016.
Assets acquired and liabilities assumed under transactions that do not meet the criteria of a business combination under ASC Topic 805, Business Combinations are accounted for as an asset acquisition and are recorded based on the fair value of the total consideration transferred on the acquisition date using the lowest observable inputs available. In connection with the QStar Acquisition, the Company issued approximately 13.4 million shares of common stock as a component of the total consideration transferred to the sellers on December 21, 2016. Fair value of the equity consideration transferred was based on the closing price of the Company’s common stock on the date of acquisition, as adjusted using an option pricing model to account for the lack of marketability of the shares issued.
Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale for additional discussion.
Net Profits Plan
The Net Profits Plan is a liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income valuation technique, which converts expected future cash flow amounts to a single present value amount. The estimate is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. Due to divestitures of assets subject to the Net Profits Plan in recent years, the liability has been significantly reduced and is no longer considered a significant accounting estimate. The Net Profits Plan liability is included in the other noncurrent liabilities line on the accompanying balance sheets.
The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Beginning balance | $ | 7,611 |
| | $ | 27,136 |
| | $ | 56,985 |
|
Net increase (decrease) in liability (1) | 23,757 |
| | (12,238 | ) | | (12,492 | ) |
Net settlements (1) (2) | (30,957 | ) | | (7,287 | ) | | (17,357 | ) |
| Transfers in (out) of Level 3 | — |
| | — |
| | — |
|
| Ending balance | $ | 411 |
| | $ | 7,611 |
| | $ | 27,136 |
|
| |
(1)
| Net changes in the Company’s Net Profits Plan liability are shown in the change in Net Profits Plan liability line item of the accompanying statements of operations. |
| |
(2)
| Settlements represent cash payments made or accrued under the Net Profits Plan and are recognized as compensation expense or a reduction to the net gain on divestiture activity line in the accompanying statements of operations, as discussed in Note 7 – Compensation Plans.
|
inherent acreage risks.
Long-Term Debt
The following table reflects the fair value of the Senior Notes and Senior Convertible NotesCompany’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2016,2019, or 2015,2018, as they arewere recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 -– Long-Term Debt for additional discussion.
|
| | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
| | Principal Amount | | Fair Value | | Principal Amount | | Fair Value |
| | (in thousands) |
| 6.125% Senior Notes due 2022 | $ | 476,796 |
| | $ | 481,564 |
| | $ | 476,796 |
| | $ | 452,336 |
|
| 5.0% Senior Notes due 2024 | $ | 500,000 |
| | $ | 479,815 |
| | $ | 500,000 |
| | $ | 439,265 |
|
| 5.625% Senior Notes due 2025 | $ | 500,000 |
| | $ | 475,835 |
| | $ | 500,000 |
| | $ | 436,460 |
|
| 6.75% Senior Notes due 2026 | $ | 500,000 |
| | $ | 494,860 |
| | $ | 500,000 |
| | $ | 448,305 |
|
| 6.625% Senior Notes due 2027 | $ | 500,000 |
| | $ | 493,750 |
| | $ | 500,000 |
| | $ | 442,500 |
|
| 1.50% Senior Convertible Notes due 2021 | $ | 172,500 |
| | $ | 164,430 |
| | $ | 172,500 |
| | $ | 158,614 |
|
|
| | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2016 | | 2015 |
| | Principal Amount | | Fair Value | | Principal Amount | | Fair Value |
| | (in thousands) |
| 6.50% Senior Notes due 2021 | $ | 346,955 |
| | $ | 354,546 |
| | $ | 350,000 |
| | $ | 262,938 |
|
| 6.125% Senior Notes due 2022 | $ | 561,796 |
| | $ | 570,925 |
| | $ | 600,000 |
| | $ | 440,250 |
|
| 6.50% Senior Notes due 2023 | $ | 394,985 |
| | $ | 403,134 |
| | $ | 400,000 |
| | $ | 296,000 |
|
| 5.0% Senior Notes due 2024 | $ | 500,000 |
| | $ | 475,975 |
| | $ | 500,000 |
| | $ | 334,065 |
|
| 5.625% Senior Notes due 2025 | $ | 500,000 |
| | $ | 485,000 |
| | $ | 500,000 |
| | $ | 326,875 |
|
| 6.75% Senior Notes due 2026 | $ | 500,000 |
| | $ | 516,565 |
| | $ | — |
| | $ | — |
|
| 1.50% Senior Convertible Notes due 2021 | $ | 172,500 |
| | $ | 202,189 |
| | $ | — |
| | $ | — |
|
The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.
Note 12 - Leases
Effective January 1, 2019, the Company adopted Topic 842, which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company adopted this standard using the modified retrospective method and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance. As of December 31, 2019, the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 does not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases.
As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance.
The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include:
Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception.
Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company.
Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, midstream agreements, vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases with terms greater than 12 months at commencement, remaining lease terms range from less than one year to approximately six years. The weighted-average lease term remaining for these leases is approximately three years. Certain leases also contain optional extension periods that allow for terms to be extended for up to an additional 10 years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one year. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement.
Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. For example, costs associated with drilling rigs and completion crews that are considered ROU assets are typically capitalized as part of the development of the Company’s oil and gas properties. Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs.
For the year ended December 31, 2019, total costs related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, were $442.9 million. This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.
Components of the Company’s total lease cost, whether capitalized or expensed, for the year ended December 31, 2019, were as follows:
|
| | | |
| | For the Year Ended December 31, 2019 |
| | |
| Operating lease cost | $ | 35,570 |
|
Short-term lease cost (1) | 301,373 |
|
Variable lease cost (2) | 106,006 |
|
Total lease cost (3) | $ | 442,949 |
|
| |
(1) | Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements. |
| |
(2) | Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements. |
| |
(3) | Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset. |
Other information related to the Company’s leases for the year ended December 31, 2019, was as follows:
|
| | | |
| | For the Year Ended December 31, 2019 |
| | (in thousands) |
| Cash paid for amounts included in the measurement of lease liabilities: | |
| Operating cash flows from operating leases | $ | 12,074 |
|
| Investing cash flows from operating leases | $ | 24,129 |
|
| Right-of-use assets obtained in exchange for new operating lease liabilities | $ | 25,360 |
|
Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2019, were as follows:
|
| | | |
| | As of December 31, 2019 |
| | (in thousands) |
| 2020 | $ | 21,102 |
|
| 2021 | 12,600 |
|
| 2022 | 5,749 |
|
| 2023 | 3,602 |
|
| 2024 | 2,081 |
|
| Thereafter | 1,639 |
|
| Total Lease payments | $ | 46,773 |
|
Less: Imputed interest (1) | (4,447 | ) |
| Total | $ | 42,326 |
|
| |
(1) | The weighted-average discount rate used to determine the operating lease liability as of December 31, 2019 was 6.6 percent. |
Amounts recorded on the accompanying balance sheets for operating leases as of December 31, 2019, were as follows:
|
| | | |
| | As of December 31, 2019 |
| | (in thousands) |
| Other noncurrent assets | $ | 39,717 |
|
| | |
| Other current liabilities | $ | 19,189 |
|
| Other noncurrent liabilities | $ | 23,137 |
|
As of December 31, 2019, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future.
Note 12 - Acquisition13 – Accounts Receivable and Development AgreementAccounts Payable and Accrued Expenses
Accounts receivable are comprised of the following accruals:
In June 2011, |
| | | | | | | |
| | As of December 31, |
| | 2019 |
| 2018 |
| | (in thousands) |
| Oil, gas, and NGL production revenue | $ | 146,308 |
| | $ | 107,230 |
|
| Amounts due from joint interest owners | 22,681 |
| | 31,497 |
|
| State severance tax refunds | 4,069 |
| | 4,415 |
|
| Derivative settlements | 6,868 |
| | 9,475 |
|
| Other | 4,806 |
| | 14,919 |
|
| Total accounts receivable | $ | 184,732 |
| | $ | 167,536 |
|
Accounts payable and accrued expenses are comprised of the Company entered into an Acquisitionfollowing accruals:
|
| | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Drilling and lease operating cost accruals | $ | 96,925 |
| | $ | 139,711 |
|
| Trade accounts payable | 52,094 |
| | 56,047 |
|
| Revenue and severance tax payable | 109,847 |
| | 94,806 |
|
| Property taxes | 24,535 |
| | 18,694 |
|
| Compensation | 41,540 |
| | 31,486 |
|
| Derivative settlements | 5,851 |
| | 1,287 |
|
| Interest | 44,175 |
| | 40,840 |
|
| Other | 27,041 |
| | 20,328 |
|
| Total accounts payable and accrued expenses | $ | 402,008 |
| | $ | 403,199 |
|
Note 14 – Asset Retirement Obligations
Please refer to Asset Retirement Obligations in Note 1 – Summary of Significant Accounting Policiesfor a discussion of the initial and Development Agreement with Mitsui E&P Texas LP (“Mitsui”subsequent measurements of asset retirement obligation liabilities and the “Acquisition and Development Agreement”). Pursuant tosignificant assumptions used in the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain outside-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percentestimates.
A reconciliation of certain drilling and completion costs attributable to the Company’s remaining interest in these assets until Mitsui expended an aggregate $680.0 million on behalf of the Company. The Acquisition and Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the Company that were attributable to the transferred interest during the period between the effective date and the closing date, which the parties agreed would be applied over the carry period to cover the Company’s remaining 10 percent of drilling and completion costs for the affected acreage. During the second quarter of 2014, the remainder of the carry under the Acquisition and Development Agreement was expended.total asset retirement obligation liability is as follows:
|
| | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Beginning asset retirement obligations | $ | 94,194 |
| | $ | 114,470 |
|
Liabilities incurred (1) | 3,927 |
| | 4,054 |
|
Liabilities settled (2) | (4,105 | ) | | (33,024 | ) |
| Accretion expense | 4,016 |
| | 4,438 |
|
| Revision to estimated cash flows | (11,186 | ) | | 4,256 |
|
Ending asset retirement obligations (3) | $ | 86,846 |
| | $ | 94,194 |
|
| |
(1) | Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. |
| |
(2) | Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. |
| |
(3) | Balances as of December 31, 2019, and 2018, included $2.7 million and $2.3 million, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets. |
Note 13 -15 – Suspended Well Costs
The following table reflects the net changes in capitalized exploratory well costs during 2016, 2015,2019, 2018, and 2014.2017. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (in thousands) |
| Beginning balance | $ | 11,197 |
| | $ | 49,446 |
| | $ | 19,846 |
|
| Additions to capitalized exploratory well costs pending the determination of proved reserves | 11,925 |
| | 11,197 |
| | 49,446 |
|
| Divestitures | — |
| | (109 | ) | | — |
|
| Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | (11,197 | ) | | (49,337 | ) | | (19,846 | ) |
| Capitalized exploratory well costs charged to expense | — |
| | — |
| | — |
|
| Ending balance | $ | 11,925 |
| | $ | 11,197 |
| | $ | 49,446 |
|
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Beginning balance on January 1, | $ | 11,952 |
| | $ | 43,589 |
| | $ | 34,527 |
|
| Additions to capitalized exploratory well costs pending the determination of proved reserves | 19,846 |
| | 11,952 |
| | 43,589 |
|
| Divestitures | — |
| | (809 | ) | | — |
|
| Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | (11,952 | ) | | (18,485 | ) | | (33,340 | ) |
| Capitalized exploratory well costs charged to expense | — |
| | (24,295 | ) | | (1,187 | ) |
| Ending balance at December 31, | $ | 19,846 |
| | $ | 11,952 |
| | $ | 43,589 |
|
As of December 31, 2016,2019, there were no0 exploratory well costs that were capitalized for more than one year.
Note 14 - Exit and Disposal Costs
2016 Activity. In the third quarter of 2016, the Company conducted a company-wide reduction in workforce and in the fourth quarter of 2016, the Company closed its Billings, Montana regional office and relocated certain employees to the Company’s corporate office in Denver, Colorado or other Company offices. This decision was made in an effort to reduce future costs and better position the Company for efficient growth in response to prolonged commodity price weakness. The Company expects to incur approximately $7.6 million of total exit and disposal costs related to termination benefits, relocation of certain employees, and other related matters, excluding lease expenses discussed below, all of which are included in general and administrative expense in the accompanying statements of operations. The Company incurred $5.1 million of exit and disposal costs during the year ended December 31, 2016, and expects to incur the remaining costs in early 2017. Upon closing the office in Billings, Montana, the Company paid $3.2 million to the lessor to terminate the lease.
2015 Activity. In conjunction with its Mid-Continent divestitures in 2015, the Company closed its Tulsa, Oklahoma regional office and incurred $9.3 million of exit and disposal costs, excluding the lease expenses discussed below, all of which were included in general and administrative expense in the accompanying statements of operations for the year ended December 31, 2015. The Company subsequently subleased its space for a portion of the remaining lease term. As of December 31, 2016, the Company is obligated to pay lease costs of approximately $3.8 million, net of expected income from subleased office space, which will be expensed over the remaining duration of the lease, which expires in 2022.
Note 15 - Equity
On August 12, 2016, the Company completed an underwritten public offering of approximately 18.4 million shares of its common stock at an offering price of $30.00 per share. Net proceeds from the offering totaled $530.9 million, after deducting underwriting discounts and commissions and offering expenses, which the Company used to partially fund the Rock Oil Acquisition that closed on October 4, 2016.
On December 7, 2016, the Company completed an underwritten public offering of approximately 10.9 million shares of its common stock at an offering price of $38.25 per share. Net proceeds from the offering totaled $403.2 million, after deducting underwriting discounts and commissions and offering expenses, which the Company used to partially fund the QStar Acquisition.
These public equity offerings were made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC.
On December 21, 2016, and as part of the QStar Acquisition, the Company issued approximately 13.4 million shares of its common stock valued at approximately $437.2 million in a private placement to the sellers as partial consideration for the acquired properties. Please refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale for additional discussion.
Supplemental Oil and Gas Information (unaudited)
Costs Incurred in Oil and Gas Producing Activities
Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| | (in thousands) | (in thousands) |
Development costs (1) | $ | 595,331 |
| | $ | 1,234,114 |
| | $ | 1,782,324 |
| $ | 913,959 |
| | $ | 1,147,574 |
| | $ | 675,523 |
|
| Exploration costs | 118,224 |
| | 132,465 |
| | 288,270 |
| 114,957 |
| | 184,930 |
| | 271,502 |
|
Acquisitions (2) | | | | | | | | | | |
| Proved properties | 201,672 |
| | 10,040 |
| | 272,902 |
| (310 | ) | | 1,312 |
| | 1,602 |
|
Unproved properties (3)(2) | 2,458,667 |
| | 18,382 |
| | 368,208 |
| 11,633 |
| | 55,688 |
| | 91,420 |
|
Total, including asset retirement obligation (4)(5) | $ | 3,373,894 |
| | $ | 1,395,001 |
| | $ | 2,711,704 |
| |
Total, including asset retirement obligations (3)(4) | | $ | 1,040,239 |
| | $ | 1,389,504 |
| | $ | 1,040,047 |
|
| |
(1) | Includes facility costs of $25.9$28.3 million, $75.6$72.6 million, and $75.1$43.8 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively. |
| |
(2) | Includes the $437.2 million value of the equity consideration given to the sellers of the QStar Acquisition. Please refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale for additional discussion.
|
| |
(3)
| Includes amounts related to leasing activity and acquiring surface rights outside of acquisitions of proved and unproved properties totaling $7.5$8.7 million, $17.5$23.4 million, and $79.5$12.8 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively. |
| |
(4)(3)
| Includes amounts relating to estimated asset retirement obligations of $32.1$(9.9) million, $38.5$7.1 million, and $11.4$13.6 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively. For the year ended December 31, 2016, $16.5 million of the estimated asset retirement obligation amount relates to acquired proved properties. |
| |
(5)(4)
| Includes capitalized interest of $17.0$18.5 million, $25.1$20.6 million, and $16.2$12.6 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively. |
Oil and Gas Reserve Quantities
The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting of reserve estimation and disclosure.
Proved reserves are the estimated quantities of oil, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of the Company’s estimated proved reserves are located in the United States.
The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended December 31, 2016.2019. The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the Company’s total calculated proved reserve PV-10 for each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
|
|
|
| | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 (1) | | 2015 (2) | | 2014 (3) | 2019 (1) | | 2018 (2) | | 2017 (3) |
| | Oil | | Gas | | NGLs | | Oil | | Gas | | NGLs | | Oil | | Gas | | NGLs | Oil | | Gas | | NGLs | | Oil | | Gas | | NGLs | | Oil | | Gas | | NGLs |
| | (MMBbl) | | (Bcf) | | (MMBbl) | | (MMBbl) | | (Bcf) | | (MMBbl) | | (MMBbl) | | (Bcf) | | (MMBbl) | (MMBbl) | | (Bcf) | | (MMBbl) | | (MMBbl) | | (Bcf) | | (MMBbl) | | (MMBbl) | | (Bcf) | | (MMBbl) |
| Total proved reserves: | Total proved reserves: | | | | | | | | | | | | | | | | | Total proved reserves: | | | | | | | | | | | | | | | | |
| Beginning of year | 145.3 |
| | 1,264.0 |
| | 115.4 |
| | 169.7 |
| | 1,466.5 |
| | 133.5 |
| | 126.6 |
| | 1,189.3 |
| | 103.9 |
| 175.7 |
| | 1,321.8 |
| | 107.4 |
| | 158.2 |
| | 1,280.1 |
| | 96.5 |
| | 104.9 |
| | 1,111.1 |
| | 105.7 |
|
| Revisions of previous estimate | (36.0 | ) | | (249.8 | ) | | (18.6 | ) | | (46.2 | ) | | (369.6 | ) | | (40.6 | ) | | (5.1 | ) | | 46.0 |
| | 7.8 |
| (19.2 | ) | | (212.5 | ) | | (40.0 | ) | | (24.0 | ) | | (219.5 | ) | | (8.0 | ) | | 1.0 |
| | 63.8 |
| | 4.9 |
|
| Discoveries and extensions | 7.8 |
| | 42.5 |
| | 4.1 |
| | 16.9 |
| | 122.3 |
| | 9.3 |
| | 15.0 |
| | 103.5 |
| | 10.5 |
| 5.4 |
| | 28.8 |
| | 2.9 |
| | 9.3 |
| | 20.3 |
| | 0.5 |
| | 11.5 |
| | 21.9 |
| | — |
|
| Infill reserves in an existing proved field | 32.3 |
| | 228.1 |
| | 18.9 |
| | 24.9 |
| | 356.2 |
| | 29.7 |
| | 32.0 |
| | 270.8 |
| | 24.1 |
| 41.8 |
| | 190.2 |
| | 11.8 |
| | 80.4 |
| | 391.5 |
| | 29.0 |
| | 79.0 |
| | 347.4 |
| | 22.9 |
|
Sales of reserves (4) | (40.0 | ) | | (46.7 | ) | | — |
| | (1.9 | ) | | (138.4 | ) | | (0.4 | ) | | (1.9 | ) | | (1.1 | ) | | — |
| (0.2 | ) | | (0.7 | ) | | — |
| | (29.6 | ) | | (48.1 | ) | | (2.7 | ) | | (25.3 | ) | | (143.8 | ) | | (26.7 | ) |
Purchases of minerals in place (4) | 12.1 |
| | 19.9 |
| | 0.1 |
| | 1.1 |
| | 0.6 |
| | — |
| | 19.8 |
| | 10.9 |
| | 0.2 |
| 2.5 |
| | 5.4 |
| | — |
| | 0.2 |
| | 0.7 |
| | — |
| | 0.8 |
| | 2.7 |
| | — |
|
| Production | (16.6 | ) | | (146.9 | ) | | (14.2 | ) | | (19.2 | ) | | (173.6 | ) | | (16.1 | ) | | (16.7 | ) | | (152.9 | ) | | (13.0 | ) | (21.9 | ) | | (109.8 | ) | | (8.1 | ) | | (18.8 | ) | | (103.2 | ) | | (7.9 | ) | | (13.7 | ) | | (123.0 | ) | | (10.3 | ) |
End of year (5) | 104.9 |
| | 1,111.1 |
| | 105.7 |
| | 145.3 |
| | 1,264.0 |
| | 115.4 |
| | 169.7 |
| | 1,466.5 |
| | 133.5 |
| |
| End of year | | 184.1 |
| | 1,223.2 |
| | 74.0 |
| | 175.7 |
| | 1,321.8 |
| | 107.4 |
| | 158.2 |
| | 1,280.1 |
| | 96.5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved developed reserves: | Proved developed reserves: | | | | | | | | | | | | | | | | | Proved developed reserves: | | | | | | | | | | | | | | | | |
| Beginning of year | 75.6 |
| | 644.4 |
| | 61.5 |
| | 89.3 |
| | 784.6 |
| | 66.7 |
| | 70.2 |
| | 569.2 |
| | 43.8 |
| 68.2 |
| | 699.1 |
| | 60.1 |
| | 58.6 |
| | 642.9 |
| | 49.0 |
| | 48.5 |
| | 609.1 |
| | 58.6 |
|
| End of year | 48.5 |
| | 609.1 |
| | 58.6 |
| | 75.6 | | 644.4 |
| | 61.5 |
| | 89.3 |
| | 784.6 |
| | 66.7 |
| 85.0 |
| | 712.1 |
| | 43.4 |
| | 68.2 | | 699.1 |
| | 60.1 |
| | 58.6 | | 642.9 |
| | 49.0 |
|
| Proved undeveloped reserves: | Proved undeveloped reserves: | | | | | | | | | | | | | | | Proved undeveloped reserves: | | | | | | | | | | | | | | |
| Beginning of year | 69.6 |
|
| 619.7 |
|
| 53.9 |
| | 80.4 |
| | 682.0 |
| | 66.8 |
| | 56.3 |
| | 620.1 |
| | 60.2 |
| 107.6 |
|
| 622.7 |
|
| 47.2 |
| | 99.6 |
| | 637.2 |
| | 47.6 |
| | 56.4 |
| | 502.0 |
| | 47.1 |
|
| End of year | 56.4 |
|
| 502.0 |
|
| 47.1 |
| | 69.6 |
| | 619.7 |
| | 53.9 |
| | 80.4 |
| | 682.0 |
| | 66.8 |
| 99.1 |
|
| 511.1 |
|
| 30.6 |
| | 107.6 |
| | 622.7 |
| | 47.2 |
| | 99.6 |
| | 637.2 |
| | 47.6 |
|
Note: Amounts may not calculate due to rounding.
| |
(1) | For the year ended December 31, 2019, the Company added 98.4 MMBOE from its drilling program and further development plan optimization. These additions were offset by net downward revisions of 94.7 MMBOE, which were primarily driven by declining commodity prices during 2019. Please refer to Areas of Operation in Part I, Items 1 and 2 of this report, and to Oil and Gas Reserve Quantities in Critical Accounting Policies and Estimatesin Part II, Item 7 of this report for additional information. |
| |
(2) | For the year ended December 31, 2016,2018, the Company added 108.2188.0 MMBOE from its drilling program and acquired 15.5 MMBOE. These additions were offset bythrough development plan optimization. The Company divested 40.3 MMBOE during 2018, primarily as a result of the PRB Divestiture, Divide County Divestiture, and Halff East Divestiture. The Company also had net negative engineeringdownward revisions of 96.268.8 MMBOE, consisting of 18.1 MMBOE of negative performance revisions, a 35.1 MMBOE negative price revision, and the removal of 43.0 MMBOE of certain longer term proved undeveloped reserves reflecting the Company’s shift to developwhich resulted primarily from changes in development plans in its predominately unproven Midland Basin properties. Additionally, the Company sold 47.7 MMBOE during 2016.Eagle Ford shale program. |
| |
(2)(3)
| For the year ended December 31, 2015,2017, the Company added 160.6175.0 MMBOE from its drilling program, the majority of whichprogram. The Company divested 76.0 MMBOE during 2017, including 72.5 MMBOE related to activity in the Eagle Ford shale and Bakken/Three Forks resource plays. The Company had net negative engineering revisions of 148.6 MMBOE, consisting of 47.3 MMBOE of positive performance revisions in the Eagle Ford shale and Bakken/Three Forks resource plays resulting from enhanced completions and reductions in operating expenses, offset by a 116.5 MMBOE negative price revision due to the decline in commodity prices in 2015 and the removal of 79.4 MMBOE of proved undeveloped reserves due to the five-year rule. Additionally, the Company sold 25.4 MMBOE in 2015. |
| |
(3)
| For the year ended December 31, 2014, the Company added 143.9 MMBOE from its drilling program and had upward engineering revisions of 10.4 MMBOE related primarily to improved performance and lower operating expenses in its operatedoutside-operated Eagle Ford shale assets. |
| |
(4) | Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale, and Acquisitionsfor additional information. |
| |
(5)
| As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, the Company entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 74.0 MMBOE of the Company’s proved reserves as of December 31, 2016. Additionally, subsequent to December 31, 2016, the Company announced plans to sell its Divide County, North Dakota assets. |
Standardized Measure of Discounted Future Net Cash Flows
The Company computes a standardized measure of future net cash flows (“Standardized Measure”) and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-endyear end estimated future reserve quantities. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual discount factor.
Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the estimated proved reserves in place at the end of the period using year-endyear end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities.
The assumptions used to compute the Standardized Measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the Standardized Measure:
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Oil (per Bbl) | $ | 37.22 |
| | $ | 42.98 |
| | $ | 84.65 |
| $ | 53.68 |
| | $ | 57.76 |
| | $ | 48.57 |
|
| Gas (per Mcf) | $ | 2.45 |
| | $ | 2.48 |
| | $ | 4.63 |
| $ | 2.49 |
| | $ | 3.49 |
| | $ | 3.20 |
|
| NGLs (per Bbl) | $ | 16.38 |
| | $ | 16.99 |
| | $ | 35.48 |
| $ | 18.88 |
| | $ | 26.23 |
| | $ | 23.33 |
|
The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based on the Standardized Measure.
|
| | | | | | | | | | | |
| | As of December 31, |
| | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Future cash inflows | $ | 8,359,938 |
| | $ | 11,337,865 |
| | $ | 25,897,730 |
|
| Future production costs | (4,634,649 | ) | | (6,234,687 | ) | | (9,986,239 | ) |
| Future development costs | (1,636,077 | ) | | (2,005,599 | ) | | (3,294,164 | ) |
Future income taxes (1) | — |
| | — |
| | (3,511,352 | ) |
| Future net cash flows | 2,089,212 |
| | 3,097,579 |
| | 9,105,975 |
|
| 10 percent annual discount | (937,099 | ) | | (1,307,053 | ) | | (3,407,192 | ) |
| Standardized measure of discounted future net cash flows | $ | 1,152,113 |
| | $ | 1,790,526 |
| | $ | 5,698,783 |
|
| |
(1) | | | | | | | | | | | | | | | As of December 31, | | | 2019 | | 2018 | | 2017 | | | (in thousands) | | Future cash inflows | $ | 14,327,131 |
| | $ | 17,579,432 |
| | $ | 14,035,704 |
| | Future production costs | (4,579,119 | ) | | (5,386,264 | ) | | (5,594,226 | ) | | Future development costs | (2,108,859 | ) | | (2,679,488 | ) | | (2,638,459 | ) | | Future income taxes | (579,815 | ) | | (1,012,209 | ) | | (205,694 | ) | | Future net cash flows | 7,059,338 |
| | 8,501,471 |
| | 5,597,325 |
| | 10 percent annual discount | (2,955,340 | ) | | (3,847,088 | ) | | (2,573,183 | ) | | Standardized measure of discounted future net cash flows | $ | 4,103,998 |
| | $ | 4,654,383 |
| | $ | 3,024,142 |
|
| Regarding the calculation as of December 31, 2016, and 2015, after evaluating all factors and giving effect to tax basis, future tax deductions, and available tax credits, the Company determined that at price levels for each respective period, future net cash flows would not be subject to federal or state income tax for the projected life of the reserves under authoritative tax legislation. |
The principle sources of changes in the Standardized Measure were:
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| | (in thousands) | (in thousands) |
| Standardized Measure, beginning of year | $ | 1,790,526 |
| | $ | 5,698,783 |
| | $ | 4,009,439 |
| $ | 4,654,383 |
| | $ | 3,024,142 |
| | $ | 1,152,113 |
|
| Sales of oil, gas, and NGLs produced, net of production costs | (580,861 | ) | | (776,272 | ) | | (1,765,666 | ) | (1,085,041 | ) | | (1,148,991 | ) | | (745,877 | ) |
| Net changes in prices and production costs | (315,725 | ) | | (4,709,908 | ) | | (75,966 | ) | (1,539,042 | ) | | 1,010,335 |
| | 1,181,447 |
|
| Extensions, discoveries and other including infill reserves in an existing proved field, net of related costs | 242,556 |
| | 386,069 |
| | 1,819,657 |
| 887,254 |
| | 2,218,475 |
| | 1,638,734 |
|
| Sales of reserves in place | (377,607 | ) | | (262,210 | ) | | (49,736 | ) | (2,788 | ) | | (147,887 | ) | | (226,528 | ) |
| Purchase of reserves in place | 115,270 |
| | 4,686 |
| | 413,175 |
| 57,519 |
| | 1,818 |
| | 12,032 |
|
| Previously estimated development costs incurred during the period | 290,837 |
| | 449,738 |
| | 1,015,694 |
| 736,770 |
| | 445,638 |
| | 121,879 |
|
| Changes in estimated future development costs | 27,961 |
| | 191,447 |
| | 138,247 |
| 132,825 |
| | (34,871 | ) | | (116,609 | ) |
| Revisions of previous quantity estimates | (124,845 | ) | | (1,819,639 | ) | | 167,500 |
| (398,409 | ) | | (611,168 | ) | | 103,916 |
|
| Accretion of discount | 179,050 |
| | 761,746 |
| | 552,852 |
| 510,427 |
| | 305,657 |
| | 115,211 |
|
| Net change in income taxes | — |
| | 1,918,670 |
| | (399,587 | ) | 191,040 |
| | (449,884 | ) | | (32,426 | ) |
| Changes in timing and other | (95,049 | ) | | (52,584 | ) | | (126,826 | ) | (40,940 | ) | | 41,119 |
| | (179,750 | ) |
| Standardized Measure, end of year | $ | 1,152,113 |
| | $ | 1,790,526 |
| | $ | 5,698,783 |
| $ | 4,103,998 |
| | $ | 4,654,383 |
| | $ | 3,024,142 |
|
Quarterly Financial Information (unaudited)
The Company’s quarterly financial information for fiscal years 20162019 and 20152018 is as follows (in thousands, except per share amounts)data): |
| | | | | | | | | | | | | | | |
| | First | | Second | | Third | | Fourth |
| | Quarter | | Quarter | | Quarter | | Quarter |
Year Ended December 31, 2016 (2) | | | | | | | |
| Total operating revenues and other income | $ | 143,076 |
| | $ | 341,814 |
| | $ | 352,660 |
| | $ | 379,900 |
|
| Total operating expenses | 669,801 |
| | 572,363 |
| | 370,314 |
| | 664,287 |
|
| Loss from operations | $ | (526,725 | ) | | $ | (230,549 | ) | | $ | (17,654 | ) | | $ | (284,387 | ) |
| Loss before income taxes | $ | (542,085 | ) | | $ | (264,579 | ) | | $ | (64,639 | ) | | $ | (330,613 | ) |
| Net loss | $ | (347,210 | ) | | $ | (168,681 | ) | | $ | (40,907 | ) | | $ | (200,946 | ) |
Basic net loss per common share(1) | $ | (5.10 | ) | | $ | (2.48 | ) | | $ | (0.52 | ) | | $ | (2.20 | ) |
Diluted net loss per common share(1) | $ | (5.10 | ) | | $ | (2.48 | ) | | $ | (0.52 | ) | | $ | (2.20 | ) |
| Dividends declared per common share | $ | 0.05 |
| | $ | — |
| | $ | 0.05 |
| | $ | — |
|
| | | | | | | | |
Year Ended December 31, 2015 (3) | | | | | | | |
| Total operating revenues and other income | $ | 365,934 |
| | $ | 516,146 |
| | $ | 371,151 |
| | $ | 303,734 |
|
| Total operating expenses | 420,369 |
| | 567,025 |
| | 339,047 |
| | 809,307 |
|
| Income (loss) from operations | $ | (54,435 | ) | | $ | (50,879 | ) | | $ | 32,104 |
| | $ | (505,573 | ) |
| Loss before income taxes | $ | (86,511 | ) | | $ | (98,211 | ) | | $ | (1,026 | ) | | $ | (537,113 | ) |
| Net income (loss) | $ | (53,058 | ) | | $ | (57,508 | ) | | $ | 3,114 |
| | $ | (340,258 | ) |
Basic net income (loss) per common share(1) | $ | (0.79 | ) | | $ | (0.85 | ) | | $ | 0.05 |
| | $ | (5.01 | ) |
Diluted net income (loss) per common share(1) | $ | (0.79 | ) | | $ | (0.85 | ) | | $ | 0.05 |
| | $ | (5.01 | ) |
| Dividends declared per common share | $ | 0.05 |
| | $ | — |
| | $ | 0.05 |
| | $ | — |
|
| |
(1)
| Amounts may not sum due to rounding. |
| |
(2)
| First quarter of 2016 included the following: |
$272.1 million of proved and unproved property impairments on the Company’s outside-operated Eagle Ford shale assets due to declining commodity prices (see Note 11 - Fair Value Measurements)
$69.0 million net pre-tax loss on divestiture activity related to write-downs on certain non-core assets held for sale (see Note 3 - Acquisitions, Divestitures, and Assets Held for Sale) |
| | | | | | | | | | | | | | | |
| | First | | Second | | Third | | Fourth |
| | Quarter | | Quarter | | Quarter | | Quarter |
Year Ended December 31, 2019 (1) | | | | | | | |
| Total operating revenues and other income | $ | 340,930 |
| | $ | 407,172 |
| | $ | 390,317 |
| | $ | 451,686 |
|
| Total operating expenses | 526,239 |
| | 303,005 |
| | 290,840 |
| | 539,989 |
|
| Income (loss) from operations | $ | (185,309 | ) | | $ | 104,167 |
| | $ | 99,477 |
| | $ | (88,303 | ) |
| Income (loss) before income taxes | $ | (223,606 | ) | | $ | 63,978 |
| | $ | 58,345 |
| | $ | (129,761 | ) |
| Net income (loss) | $ | (177,568 | ) | | $ | 50,388 |
| | $ | 42,234 |
| | $ | (102,055 | ) |
| Basic net income (loss) per common share | $ | (1.58 | ) | | $ | 0.45 |
| | $ | 0.37 |
| | $ | (0.90 | ) |
| Diluted net income (loss) per common share | $ | (1.58 | ) | | $ | 0.45 |
| | $ | 0.37 |
| | $ | (0.90 | ) |
| Dividends declared per common share | $ | 0.05 |
| | $ | — |
| | $ | 0.05 |
| | $ | — |
|
| | | | | | | | |
Year Ended December 31, 2018 (2) | | | | | | | |
| Total operating revenues and other income | $ | 769,595 |
| | $ | 443,916 |
| | $ | 459,369 |
| | $ | 394,192 |
|
| Total operating expenses | 310,527 |
| | 387,768 |
| | 568,013 |
| | (35,573 | ) |
| Income (loss) from operations | $ | 459,068 |
| | $ | 56,148 |
| | $ | (108,644 | ) | | $ | 429,765 |
|
| Income (loss) before income taxes | $ | 416,392 |
| | $ | 16,296 |
| | $ | (172,671 | ) | | $ | 391,760 |
|
| Net income (loss) | $ | 317,401 |
| | $ | 17,197 |
| | $ | (135,923 | ) | | $ | 309,732 |
|
| Basic net income (loss) per common share | $ | 2.84 |
| | $ | 0.15 |
| | $ | (1.21 | ) | | $ | 2.76 |
|
| Diluted net income (loss) per common share | $ | 2.81 |
| | $ | 0.15 |
| | $ | (1.21 | ) | | $ | 2.73 |
|
| Dividends declared per common share | $ | 0.05 |
| | $ | — |
| | $ | 0.05 |
| | $ | — |
|
$14.2 million net derivative gain (see Note 10 - Derivative Financial Instruments)
$15.7 million net gain on the repurchase of a portion of the Company’s Senior Notes (see Note 5 - Long-Term Debt)
Second quarter of 2016 included the following:
$50.0 million net pre-tax gain on divestiture activity related to an increase in fair value less costs to sell on assets held for sale (see Note 3 - Acquisitions, Divestitures, and Assets Held for Sale)
$163.4 million net derivative loss (see Note 10 - Derivative Financial Instruments)
Third quarter of 2016 included the following:
$11.6 million of proved and unproved property impairments (see Note 11 - Fair Value Measurements)
$22.4 million net pre-tax gain on divestiture activity upon closing divestitures in the Company’s Rocky Mountain and Permian regions (see Note 3 - Acquisitions, Divestitures, and Assets Held for Sale)
$28.0 million net derivative gain (see Note 10 - Derivative Financial Instruments)
Fourth quarter of 2016 included the following:
$151.2 million of proved and unproved property impairments related primarily to negative performance revisions on the Company’s Powder River Basin assets (see Note 11 - Fair Value Measurements)
$33.7 million net pre-tax gain on divestiture activity upon closing the Raven/Bear Den divestiture (see Note 3 - Acquisitions, Divestitures, and Assets Held for Sale)
$129.5 million net derivative loss (see Note 10 - Derivative Financial Instruments)
____________________________________________
| |
(3)(1)
| First quarterResults of 2015 includedoperations during 2019 were primarily impacted by the following: |
$67.2•a net derivative loss of $177.1 million of proved and unproved property impairments due to commodity price declines and the Company’s decision to reduce capital investedrecorded in the developmentfirst quarter of certain prospects in its South Texas & Gulf Coast and Permian regions and acreage it no longer intended to develop (see Note 11 - Fair Value Measurements)
2019,$16.3 million of expense relating to an exploratory dry hole
$35.8 million net pre-tax loss on divestiture activity related to write-downs on certain assets held for sale in the Company’s Mid-Continent region (see Note 3 - Acquisitions, Divestitures, and Assets Held for Sale)
$154.2 million•a net derivative gain (see of $79.7 million recorded in the second quarter of 2019,
•a net derivative gain of $100.9 million recorded in the third quarter of 2019, and
•a net derivative loss of $101.0 million recorded in the fourth quarter of 2019.
Please refer to Note 10 -– Derivative Financial Instruments)
Second quarter of 2015 included the following:
$18.7 million of proved and unproved property impairments (see Note 11 - Fair Value Measurements)
$71.9 million net pre-tax gain on divestiture activity upon closing the sale of the Company’s Mid-Continent assets (see Note 3 - Acquisitions, Divestitures, and Assets Held for Sale)
$80.9 million net derivative loss (see Note 10 - Derivative Financial Instruments)
$16.6 million net loss on the early extinguishment of the Company’s 2019 Notes (see Note 5 - Long-Term Debt)
Third quarter of 2015 included the following:
$62.6 million of proved and unproved property impairments primarily on legacy assets in the Company’s Rocky Mountain region as a result of the continued decline in commodity strip prices (see Note 11 - Fair Value Measurements)
$212.3 million net derivative gain (see Note 10 - Derivative Financial Instruments)
Fourth quarter of 2015 included the following:
$448.2 million of proved, unproved, and other property and equipment impairments due to continued commodity price declines, largely impacting the Company’s Powder River Basin program, as well as the Company’s decision to reduce capital invested in the development of its east Texas exploration program in its South Texas & Gulf Coast region (see Note 11 - Fair Value Measurements)
$13.8 million expense relating to exploratory dry holes
$123.3 million net derivative gain (see Note 10 - Derivative Financial Instruments)
| |
ITEM 9.(2) | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREFor the first quarter of 2018, the Company recorded an estimated $409.2 million net pre-tax gain on divestiture activity related to the PRB Divestiture, which was partially offset by a $24.1 million write-down on certain assets. During the second quarter of 2018, the Company recorded an estimated $15.7 million net pre-tax gain on divestiture activity related to the Divide County Divestiture and Halff East Divestiture (please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions). During the third quarter of 2018, the Company recorded a $26.7 million loss on the early extinguishment of its 2021 Senior Notes, 2023 Senior Notes, and a portion of its 2022 Senior Notes (please refer to Note 5 – Long-Term Debt). For the first, second, third, and fourth quarters of 2018, the Company recorded net derivative losses of $7.5 million, $63.7 million, $178.0 million, and a net derivative gain of $411.1 million. Please refer to Note 10 – Derivative Financial Instruments for greater detail. |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including theour Chief Executive Officer and theour Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute,
assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within theour company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all
potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that theseour Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the fourth quarter of 20162019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:
| |
| (i) | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; |
| |
| (ii) | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and |
| |
| (iii) | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements. |
Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016.2019. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013 framework).
Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2016.2019.
The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal control over financial reporting. That report immediately follows this report.
Report of Independent Registered Public Accounting Firm
TheTo the Stockholders and the Board of Directors and Stockholders of SM Energy Company and subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited SM Energy Company and subsidiaries’ internal control over financial reporting as of December 31, 2016,2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, SM Energy Company and subsidiaries’subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and our report dated February 20, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’sCompany’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, SM Energy Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of SM Energy Company and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016 of SM Energy Company and subsidiaries and our report dated February 23, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Denver, Colorado
February 23, 201720, 2020
ITEM 9B. OTHER INFORMATION
Amendment to By-Laws
Effective February 21, 2017, the Board of Directors amended and restated the Company’s by-laws (the “By-Laws”). The By-Laws include, among other things, the following changes:
provide the Board with explicit authority to cancel, postpone or reschedule a shareholder meeting;
provide the chairman of the meeting with explicit authority to adjourn or recess a shareholder meeting;
clarify the powers of the chairman of the meeting to conduct a shareholder meeting;
provide for additional disclosure requirements for notices of director nominations and shareholder proposals; and
clarify the procedural parameters governing the right of stockholders to take action by written consent.
The foregoing description of the terms of the By-Laws do not purport to be complete and are subject to, and qualified in their entirety by, reference to the complete text of the By-Laws, a copy of which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated by reference herein.None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The information required by this Item concerning SM Energy’sthe Company’s Directors, Executive Officers, and corporate governance is incorporated by reference to the information provided under the captions “Proposal“Proposal 1 - Election of Directors,” “Information about Executive Officers,” and “Corporate“Corporate Governance” in SM Energy’sthe Company’s definitive proxy statement for the 20172020 annual meeting of stockholders to be filed within 120 days from December 31, 2016.2019.
The information required by this Item concerning compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the information provided under the caption “Section“Section 16(a) Beneficial Ownership Reporting Compliance” in SM Energy’sthe Company’s definitive proxy statement for the 20172020 annual meeting of stockholders to be filed within 120 days from December 31, 2016.2019.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information provided under the captions “Executive“Executive Compensation” and “Director“Director Compensation” in SM Energy’sthe Company’s definitive proxy statement for the 20172020 annual meeting of stockholders to be filed within 120 days from December 31, 2016.2019.
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ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by reference to the information provided under the caption “Security“Security Ownership of Certain Beneficial Owners and Management” in SM Energy’sthe Company’s definitive proxy statement for the 20172020 annual meeting of stockholders to be filed within 120 days from December 31, 2016.2019.
Securities Authorized for Issuance Under Equity Compensation Plans.SM Energy The Company has the Equity Planequity compensation plans under which options and shares of SM Energythe Company’s common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of Directors. OurThe Company’s stockholders have approved this plan. See these plans. Please refer to Note 7 – Compensation Plans included in Part II, Item 8 of this report for further information about the material terms of ourthe Company’s equity compensation plans. The following table is a summary of the shares of common stock authorized for issuance under equity compensation plans as of December 31, 2016:2019:
| | | | | (a) | | (b) | | (c) | | (a) | | (b) | | (c) |
| Plan category | | Number of securities to be issued upon exercise of outstanding options, warrants, and rights | | Weighted-average exercise price of outstanding options, warrants, and rights | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | | Number of securities to be issued upon exercise of outstanding options, warrants, and rights | | Weighted-average exercise price of outstanding options, warrants, and rights | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) |
| Equity compensation plans approved by security holders: | | | | | | | | | | | | |
Equity Incentive Compensation Plan | | | | | | | | | | | | |
Stock options and incentive stock options (1) | | — |
| | $ | — |
| | | |
Restricted stock (1)(3) | | 604,116 |
| | N/A |
| | | |
Performance share units (1)(3)(4) | | 878,844 |
| | N/A |
| | | |
Restricted stock units (2) | | | 1,540,925 |
| | N/A |
| | |
Performance share units (2)(3) | | | 2,044,882 |
| | N/A |
| | |
| Total for Equity Incentive Compensation Plan | | 1,482,960 |
| | $ | — |
| | 5,531,614 |
| | 3,585,807 |
| | $ | — |
| | 4,385,709 |
|
Employee Stock Purchase Plan (2) | | — |
| | — |
| | 731,572 |
| |
Employee Stock Purchase Plan (4) | | | — |
| | — |
| | 1,299,003 |
|
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total for all plans | | 1,482,960 |
| | $ | — |
| | 6,263,186 |
| | 3,585,807 |
| | $ | — |
| | 5,684,712 |
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____________________________________________
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(1) | In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energythe Company or any affiliate of SM Energy. Ourthe Company. The Company’s Board of Directors approved amendments to the Equity Plan in 2009, 2010, 2013, 2016, and 20162018 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The number of shares of the Company’s common stock underlying awards granted in 2016, 2015,2019, 2018, and 20142017 under the Equity Plan were 918,509, 714,949,1,868,776, 1,220,217, and 464,641,2,078,878, respectively. |
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(2) | RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per unit fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per unit fair value for the outstanding RSUs and PSUs was $16.04 and $16.89, respectively. Please refer to Note 7 – Compensation Plans in Part II, Item 8 of this report for additional discussion. |
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(3) | The number of awards to be issued assumes a one multiplier. The final number of shares of the Company’s common stock issued upon settlement may vary depending on the three-year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two. |
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(4) | Under the SM Energy Company ESPP, eligible employees may purchase shares of ourthe Company’s common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the common stock is 85 percent of the lower of the fair market value of the common stock on the first or last day of the six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the IRC. SharesThe number of shares of the Company’s common stock issued in 2019, 2018, and 2017 under the ESPP totaled 218,135, 197,214,were 314,868, 199,464, and 83,136 in 2016, 2015, and 2014,186,665, respectively. |
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(3) |
RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per share fair value for the outstanding RSUs and PSUs was $37.39 and $45.53, respectively. Please refer to Note 7 - Compensation Plans in Part II, Item 8 of this report for additional discussion.
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(4) | The number of awards vested assumes a one multiplier. The final number of shares issued upon settlement may vary depending on the three-year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two. |
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ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference to the information provided under the captions “Certain“Certain Relationships and Related Transactions”Transactions” and “Corporate Governance”“Corporate Governance” in SM Energy’sthe Company’s definitive proxy statement for the 20172020 annual meeting of stockholders to be filed within 120 days from December 31, 2016.2019.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference to the information provided under the captions “Independent“Independent Registered Public Accounting Firm”Firm” and “Audit“Audit Committee PreapprovalPre-approval Policy and Procedures”Procedures” in SM Energy’sthe Company’s definitive proxy statement for the 20172020 annual meeting of stockholders to be filed within 120 days from December 31, 2016.2019.
PART IV
ITEM 15. EXHIBITS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Consolidated Financial Statements and Financial Statement Schedules:
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| Report of Independent Registered Public Accounting Firm | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Operations | |
| Consolidated Statements of Comprehensive Income (Loss) | |
| Consolidated Statements of Stockholders’ Equity | |
| Consolidated Statements of Cash Flows | |
| Notes to Consolidated Financial Statements | |
All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.
(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:
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Exhibit Number | Description |
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1.1 | UnderwritingMembership Interest Purchase Agreement dated May 7, 2015, among SM Energy Company, and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner, & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of the several underwriters (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on May 8, 2015, and incorporated herein by reference)
|
1.2 | Underwriting Agreement dated August 8, 2016 by and among SM Energy Company and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference) |
1.3 | Underwriting Agreement dated August 8, 2016 by and among SM Energy Company and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein (filed as Exhibit 1.2 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference) |
1.4 | Underwriting Agreement dated September 7, 2016 by and among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities, LLC, and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on September 12, 2016, and incorporated herein by reference) |
1.5 | Underwriting Agreement, dated DecemberJanuary 1, 2016, by and among SM Energy Company and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on December 7, 2016, and incorporated herein by reference) |
2.1 | Acquisition and Development Agreement dated June 29, 20112017 between SM Energy Company and Mitsui E&P Texas LP (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference) |
2.2 | First Amendment to Acquisition and Development Agreement dated October 13, 2011 between SM Energy Company and Mitsui E&P Texas LP (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference) |
2.3*** | Purchase and Sale Agreement dated November 4, 2013, among SM Energy Company, EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., and EnerVest Energy Institutional Fund XIII-WIC, L.P. (filed as Exhibit 2.4 to the registrant’s Amendment to the Annual Report on Form 10-K/A filed on May 9, 2014 for the year ended December 31, 2013, and incorporated herein by reference) |
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2.4*** | Purchase and Sale Agreement dated July 29, 2014 between SM Energy Company and Baytex Energy USAVenado EF LLC (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014,March 31, 2017, and incorporated herein by reference) |
2.5 | |
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2.6 | Purchase and Sale Agreement, dated October 17, 2016, by and between SM Energy Company and QStar LLC (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and incorporated herein by reference) |
2.7 | Letter Agreement dated October 17, 2016, by and among SM Energy Company, QStar LLC, and RRP-QStar, LLC (filed as Exhibit 2.2 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and incorporated herein by reference)
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2.8 | Purchase and Sale Agreement dated October 17, 2016, by and between SM Energy Company and Oasis Petroleum North America LLC (filed as Exhibit 2.3 to the registrant’s Current Report on Form 8-K filed on October 21, 2016, and incorporated herein by reference) |
3.1 | |
3.2* | |
4.1 | Indenture related to the 6.625% Senior Notes due 2019, dated February 7, 2011, by and between SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.13.2 to the registrant’s CurrentAnnual Report on Form 8-K filed on February 10, 2011,10-K for the year ended December 31, 2016, and incorporated herein by reference) |
4.2 | Indenture related to the 6.50% Senior Notes due 2021, dated November 8, 2011, by and among SM Energy Company, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on November 10, 2011, and incorporated herein by reference) |
4.3 | Indenture related to the 6.50% Senior Notes due 2023, dated June 29, 2012, between SM Energy Company, as Issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by reference) |
4.4 | |
4.5 | |
4.6 | |
4.7 | |
4.8 | 2019 Notes Supplemental Indenture (filed as Exhibit 4.3 to the registrant’s Current Report on Form 8-K filed on May 21, 2015 and incorporated herein by reference) |
4.9 | |
4.10 | |
4.11 | |
4.12† | Equity Incentive Compensation Plan, amended |
4.13* | Lock-Up and Registration Rights Agreement, dated December 21, 2016, by and among SM Energy Company, QStar LLC and RRP-QStar, LLC |
10.1† | Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference) |
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10.2† | Incentive Stock Option Plan, |
10.3 | |
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| Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.210.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference) |
10.4 | |
10.5† | |
10.6* | |
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10.8† | |
10.9+ | |
10.10 | |
10.11 | |
10.12 | |
10.13† | |
10.14† | |
10.15† | |
10.16† | Equity Incentive Compensation Plan, As Amended as of May 22, 2013 (filed as Annex A to the registrant’s Schedule 14A filed on April 11, 2013, and incorporated herein by reference) |
10.17 | Fifth Amended and Restated Credit Agreement dated April 12, 2013, among SM Energy Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April 15, 2013, and incorporated herein by reference) |
10.18† | Form of Performance Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference) |
10.19† | Form of Restricted Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference) |
10.20† | Performance Stock Unit Award Agreement as of July 1, 2016 (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference) |
10.21† | Restricted Stock Unit Award Agreement as of July 1, 2016 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference) |
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10.22† | Non-Employee Director Restricted Stock Award Agreement as of May 25, 2016 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference) |
10.23† | SM Energy Company Non-Qualified Deferred Compensation Plan as of March 10, 2014 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on January 24, 2014, and incorporated herein by reference) |
10.24† | |
10.25† | |
10.26* | |
10.27 | Second Amendment to the Fifth |
10.28 | Third Amendment to Fifth Amended and Restated Credit Agreement, dated May 20, 2015, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2015, and incorporated herein by reference) |
10.29 | Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated October 7, 2015,of September 28, 2018, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on October 8, 2015,4, 2018, and incorporated herein by reference) |
10.30 | Fifth Amendment to Fifth Amended and Restated Credit Agreement, dated November 11, 2015, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on November 11, 2015, and incorporated herein by reference) |
10.31 | Sixth Amendment to Fifth Amended and Restated Credit Agreement, dated April 8, 2016, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April 13, 2016, and incorporated herein by reference) |
10.32 | Seventh Amendment to Fifth Amended and Restated Credit Agreement, dated August 8, 2016, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on August 9, 2016, and incorporated herein by reference) |
10.33 | Eighth Amendment to Fifth Amended and Restated Credit Agreement, dated September 30, 2016, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on October 6, 2016 and incorporated herein by reference) |
10.34† | |
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10.35† | |
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10.36* | |
10.37 | |
10.38 | |
10.39 | |
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10.40 | |
10.41 | |
10.42 | |
10.43 | |
12.1* | Computation |
21.1* | |
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101.INS*101.INS | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
| 101.SCH* | Inline XBRL Schema Document |
| 101.CAL* | Inline XBRL Calculation Linkbase Document |
| 101.LAB* | Inline XBRL Label Linkbase Document |
| 101.PRE* | Inline XBRL Presentation Linkbase Document |
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document |
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS) |
* Filed with this Form 10-K.report.
** Furnished with this Form 10-K.report.
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| *** | Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934.Act. |
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| † | Exhibit constitutes a management contract or compensatory plan or agreement. |
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s†† | Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document. |
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| + | Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document. |
November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal
Revenue Code. There were no material changes to the substantive terms and conditions in this document.
(c) Financial Statement Schedules. SeePlease refer to Item 15(a) above.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act, of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | |
| | | SM ENERGY COMPANY |
| | | (Registrant) |
| | | | |
| Date: | February 23, 201720, 2020 | By: | /s/ JAVAN D. OTTOSON |
| | | | Javan D. Ottoson |
| | | | President and Chief Executive Officer |
| | | | (Principal Executive Officer) |
GENERAL POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Javan D. Ottoson and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full power to act alone, for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal year ended December 31, 2016,2019, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act, of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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| Signature | | Title | | Date |
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| /s/ JAVAN D. OTTOSON | | President, Chief Executive Officer, and Director | | February 23, 201720, 2020 |
| Javan D. Ottoson | | (Principal Executive Officer) | | |
| | | | | |
| | | | | |
| /s/ A. WADE PURSELL | | Executive Vice President and Chief Financial Officer | | February 23, 201720, 2020 |
| A. Wade Pursell | | (Principal Financial Officer) | | |
| | | | | |
| | | | | |
/s/ MARK T. SOLOMONPATRICK A. LYTLE | | Vice President - Controller and Assistant Secretary | | February 23, 201720, 2020 |
Mark T. SolomonPatrick A. Lytle | | (Principal Accounting Officer) | | |
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| Signature | | Title | | Date |
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| /s/ WILLIAM D. SULLIVAN | | Chairman of the Board of Directors | | February 23, 201720, 2020 |
| William D. Sullivan | | | | |
| | | | |
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| /s/ CARLA J. BAILO | | Director | | February 20, 2020 |
| Carla J. Bailo | | | | |
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| /s/ LARRY W. BICKLE | | Director | | February 23, 201720, 2020 |
| Larry W. Bickle | | | | |
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| /s/ STEPHEN R. BRAND | | Director | | February 23, 201720, 2020 |
| Stephen R. Brand | | | | |
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| /s/ LOREN M. LEIKER | | Director | | February 23, 201720, 2020 |
| Loren M. Leiker | | | | |
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| /s/ RAMIRO G. PERU | | Director | | February 23, 201720, 2020 |
| Ramiro G. Peru | | | | |
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| /s/ JULIO M. QUINTANA | | Director | | February 23, 201720, 2020 |
| Julio M. Quintana | | | | |
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| /s/ ROSE M. ROBESON | | Director | | February 23, 201720, 2020 |
| Rose M. Robeson | | | | |
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