ENERGEN CORP (Form: 10-K, Received: 02/28/2018 12:37:01)

Percentage Change in Proved Oil & Natural Gas Reserves From Reported Reserves December 31, 2017

(dollars in thousands)

Estimated increase in DD&A expense for 2018, net of tax

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2017


o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___

Commission file number 1-7810

Energen Corporation

(Exact name of registrant as specified in its charter)



Alabama		63-0757759
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



605 Richard Arrington Jr. Boulevard North, Birmingham, Alabama		35203-2707
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code

(205) 326-2700

Securities Registered Pursuant to Section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, $0.01 par value		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. Yes x N0 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 No x

Indicate by a 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. Yes x No o

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). Yes x No o

Indicate by a 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. x

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



Large accelerated filer x		Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o
		Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

Aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2017: $4,841,310,230

Number of shares outstanding of the registrant’s common stock as of February 20, 2018: 97,404,730 shares

DOCUMENTS INCORPORATED BY REFERENCE

Energen Corporation’s Definitive Proxy Statement for its 2018 Annual Meeting of Shareholders (Part III, Item 10-14)



	ENERGEN CORPORATION 2017 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS

		Page

Industry Glossary		3
Cautionary Statement Regarding Forward-Looking Statements		5

	PART I
Item 1.	Business	7
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	19
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
	Purchases of Equity Securities	24
Item 6.	Selected Financial Data	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 8.	Financial Statements and Supplementary Data	46
Item 9.	Changes in and Disagreements with Accountants on Accounting and
	Financial Disclosure	89
Item 9A.	Controls and Procedures	89

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	90
Item 11.	Executive Compensation	90
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	90
Item 13.	Certain Relationships and Related Transactions, and Director Independence	90
Item 14.	Principal Accountant Fees and Services	90

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	91
Item 16.	Form 10-K Summary	91
Signatures		95



INDUSTRY GLOSSARY For a more complete definition of certain terms defined below, as well as other terms and concepts applicable to successful efforts accounting, please refer to Rule 4-10(a) of Regulation S-X, promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.

Basin	A large natural depression on the earth’s surface in which sediments accumulate.

Basis	The difference between the futures price for a commodity and the corresponding cash spot price. This commonly is related to factors such as product quality, location and contract pricing.

Basin Specific	A type of derivative contract whereby the contract’s settlement price is based on specific geographic basin indices.

Bbl	A standard barrel containing 42 United States gallons.

Bcf	One billion cubic feet of natural gas.

BOE	One barrel of oil equivalent, a standard conversion used to express oil and natural gas volumes on a comparable oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of six Mcf of natural gas to one barrel of oil.

Collar	A contractual arrangement that effectively establishes a price range between a floor and a ceiling for the underlying commodity. The purchaser bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price.

Completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed Acreage	The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development Costs	Costs necessary to gain access to, prepare and equip development wells in areas of proved reserves.

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.

Downspacing	An increase in the number of available drilling locations as a result of a regulatory commission order.

Dry Well	An exploratory or a development well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploration Expenses	Costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties or exploratory geological and geophysical activities.

Exploratory Well	A well drilled to find and produce oil 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.

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 layer of rock which has distinct characteristics that differ from nearby rock.

Futures Contract	An exchange-traded contractual arrangement to buy or sell a standard quantity and quality of a commodity at a specified future date and price. Such contracts offer liquidity and minimal credit risk exposure but lack the flexibility of swap contracts.

Gross Well or Acre	A well or acre in which a working interest is owned.

Hedging	The use of derivative commodity instruments such as futures, swaps, options and collars to help reduce financial exposure to commodity price volatility.

Horizontal Drilling	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.

Hydraulic Fracturing	The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

LIBOR	London Interbank Offered Rate.

MBbl	One thousand barrels of oil.

MBOE	One thousand BOE.

MBOE/d	One thousand BOE per day.

Mcf	One thousand cubic feet of natural gas.



MMBOE	One million BOE.

MMcf	One million cubic feet of natural gas.

MMcfe	One million cubic feet of natural gas equivalent.

MMgal	One million gallons of natural gas liquids.

Natural Gas Liquids (NGL)	Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and other hydrocarbons.

Net Well or Acre	A net well or acre is deemed to exist when the sum of fractional ownership working interests in a gross well or acre equals one.

NYMEX	New York Mercantile Exchange.

Operational Enhancement	Any action undertaken to improve production efficiency of oil and natural gas wells and/or reduce well costs.

Operator	The company responsible for exploration, development and production activities for a specific project.

Pay-Add	An operation within a currently producing wellbore that attempts to access and complete an additional pay zone(s) while maintaining production from the existing completed zone(s).

Pay Zone	The stratigraphic horizon from which oil and natural gas is produced.

Production (Lifting) Costs	Costs incurred to operate and maintain wells.

Productive Well	An exploratory or a development well that is not a dry well.

Proved Developed Reserves	The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Reserves	Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved Reserves-to-Production Ratio	Ratio expressing years of supply determined by dividing the remaining recoverable proved reserves at year end by actual annual production volumes. The reserve-to-production ratio is a statistical indicator with certain limitations, including predictive value. The ratio varies over time as changes occur in production levels and remaining recoverable proved reserves.

Proved Undeveloped Reserves (PUD)	The portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.

Recompletion	An operation within an existing wellbore whereby a completion in one pay zone is abandoned in order to attempt a completion in a different pay zone.

Reservoir	A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

SEC	The United States Securities and Exchange Commission.

Service Well	A well employed for the introduction into an underground stratum of water, gas or other fluid under pressure or disposal of salt water produced with oil or other waste.

Sidetrack Well	A new section of wellbore drilled from an existing well.

Swap	A contractual arrangement in which two parties, called counterparties, effectively agree to exchange or “swap” variable and fixed rate payment streams based on a specified commodity volume. The contracts allow for flexible terms such as specific quantities, settlement dates and location but also expose the parties to counterparty credit risk.

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 and natural gas regardless of whether such acreage contains proved reserves.

Wellbore	The hole drilled by the bit that is equipped for oil and natural gas production on a completed well. Also called well or borehole.

Working Interest	Ownership interest in the oil and natural gas properties that is burdened with the cost of development and operation of the property.

Workover	A major remedial operation on a completed well to restore, maintain, or improve the well’s production such as deepening the well or plugging back to produce from a shallow formation.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

All statements, other than statements of historical fact, appearing in this report constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and are noted in Energen’s disclosure and analysis as permitted by the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. In particular, forward-looking statements may include words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”, “seek”, “will” or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this filing.

Factors that could cause actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the following:


•	volatility of oil, natural gas liquids and natural gas prices;


•	uncertainties about the estimates of our proved oil, natural gas liquids and natural gas reserves;


•	drilling risks;


•	risks associated with our concentration of operations in the Permian Basin of west Texas and New Mexico;


•	competition in the oil and natural gas industry;


•	the adequacy of our capital resources, access to financing and liquidity;


•	operational risks including risks of personal injury, property damage and environmental damage;


•	changes in the regulatory environment at the federal, state, or local level and our ability to comply with regulations promulgated by the various regulatory bodies;


•	changes in and the effects of environmental and other governmental regulation that applies to our operations, including new legislation or regulation of hydraulic fracturing, water use and disposal, permitting, climate change and other legal requirements;


•	instability in the domestic and global capital and credit markets;


•	financial strength of the parties with whom we do business, including other working interest owners, providers of midstream services, providers of oilfield services, purchasers of our oil, natural gas liquids and natural gas and the counterparties to our derivative contracts;


•	changes in domestic and global economic and business conditions that impact the demand for oil, natural gas liquids and natural gas;


•	changes in domestic and global supplies of oil, natural gas and natural gas liquids arising from economic and business conditions (including actions by the Organization of the Petroleum Exporting Countries);


•	uncertainties about our ability to successfully execute our business and financial plans and strategies, including but not limited to our ability to economically develop our proved oil, natural gas liquids and natural gas reserves and to replace those reserves as scheduled as well as our ability to project future rates of production and the timing of development expenditures;


•	risks associated with our ability to execute on property acquisitions and divestitures including market liquidity, price levels, timing and financing associated with such transactions;


•	the effectiveness of and our ability to use derivative instruments as part of our risk management activities;


•	the costs and effects of litigation; and


•	acts of nature, sabotage, terrorism or other malicious intentional acts (including cyber-attacks), war and other similar acts that disrupt operations or cause damage greater than covered by insurance.

See Item 1A, Risk Factors, for a discussion of risk factors that may affect Energen and cause material variances from forward-looking statement expectations. The Item 1A, Risk Factors, discussion is incorporated by reference into this forward-looking statement disclosure.

Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward-looking statements on information currently available to us, and we undertake no obligation to update or revise any of these statements, whether as a result of changes in underlying factors, new information, future events or other developments.

PART I

ITEM 1. BUSINESS

General

Energen Corporation (Energen or the Company) is an oil and natural gas exploration and production company engaged in the exploration, development and production of oil, natural gas liquids and natural gas. Our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources) and primarily occur within the Midland Basin, the Delaware Basin and the Central Basin Platform areas of the Permian Basin in west Texas and New Mexico. Our corporate headquarters are located in Birmingham, Alabama.

Energen was incorporated in 1978 in connection with a corporate reorganization completed in 1979 which resulted in Energen becoming the parent company to Energen Resources, which was formed in 1971, and Alabama Gas Corporation (Alagasco). In 2014, Alagasco was sold to The Laclede Group, Inc., (now Spire Inc.).

Energen maintains a web site with the address www.energen.com . Information contained on this web site is not incorporated by reference into this report. Energen makes available free of charge through its web site its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. Also, these reports are available in print upon shareholder request. These reports are available as soon as reasonably practicable after being electronically filed with or furnished to the Securities and Exchange Commission. Energen’s web site also includes its Business Conduct Guidelines, Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter and Governance and Nominations Committee Charter, each of which is available in print upon shareholder request.

Narrative Description of Business


•	Oil and Natural Gas Operations

General: Energen’s operations focus on increasing production and adding proved reserves through the development of oil, natural gas liquids and natural gas properties. In addition, Energen explores for and develops new reservoirs, primarily in areas in which it has an operating presence. All oil, natural gas liquids and natural gas production is sold to third parties. Energen operates its properties for its own interest and that of its joint interest owners. This role includes overall project management and day-to-day decision-making relative to project operations.

At the end of 2017, Energen’s proved reserves totaled 444 MMBOE. Substantially all of these proved reserves are located in the Permian Basin in west Texas and New Mexico. Approximately 57 percent of Energen’s year-end proved reserves are proved developed reserves. Energen’s proved reserves have a year-end proved reserves-to-production ratio of 16 years. Oil, natural gas liquids and natural gas represent approximately 58 percent, 20 percent and 22 percent, respectively, of Energen’s proved reserves.

Property Acquisitions and Dispositions: During 2017, Energen completed a total of $273.3 million in various purchases and renewals of unproved acquisitions, which are accounted for as asset acquisitions, including approximately $217.4 million in the Delaware Basin and approximately $36.9 million in the Midland Basin for unproved leasehold and $19.0 million for mineral purchases primarily in the Delaware Basin. Energen completed an estimated $143.7 million in various purchases and renewals of unproved leasehold largely in the Permian Basin, including approximately $77 million of acreage purchased in Lea County, New Mexico, during 2016. Energen completed an estimated total of $85.7 million in various purchases of unproved leasehold largely in the Permian Basin during 2015.

During 2016, Energen completed a series of asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico for an aggregate purchase price of $552 million . These transactions had closing dates of June 3, 7, 30, July 15 and August 9 of 2016 with various effective dates ranging from March 1, 2016 to June 30, 2016. Minor portions of the assets were transferred to other parties upon the exercise of preferential purchase rights under pre-existing joint operating agreements in the ordinary course of business. Pre-tax proceeds to Energen were approximately $532.2 million after purchase price adjustments of approximately $19 million related to the operations of the properties subsequent to the effective dates and other one-time adjustments including transfer payments and certain amounts due the buyer, but before consideration of transaction costs of approximately $5 million . In the years ended December 31, 2017 and 2016, Energen recognized pre-tax post-closing adjustment losses of $0.6 million and pre-tax gains of $246.3 million , respectively, on the sales. Energen used the proceeds from the sale to fund ongoing operations.

In March 2015, Energen completed the sale of the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado (effective as of January 1, 2015) for an aggregate purchase price of $395 million . The sales proceeds were reduced by purchase price adjustments of approximately $11 million related to the operations of the San Juan Basin properties subsequent to December 31, 2014 and one-time adjustments related primarily to liabilities assumed by the buyer, which resulted in pre-tax proceeds to Energen of approximately $384 million before consideration of transaction costs of approximately $2.8 million . Energen recognized a pre-tax gain of $27.0 million on the sale. Energen used the proceeds from the sale to reduce long-term indebtedness.

Growth Strategy: Energen is focused on increasing its oil, natural gas liquids and natural gas production and proved reserves largely through active development and/or exploratory programs in the Permian Basin. The Company seeks to expand its footprint primarily through acquisitions of proved properties and unproved leasehold within areas of existing operations. Energen operated approximately 97 percent of its proved reserves at December 31, 2017.

Energen’s capital spending plans for 2018 target an investment ranging from $1.1 billion to $1.3 billion (excluding acquisitions), the bulk of which will focus on drilling and development activities on its existing properties, all targeting the liquids-rich Permian Basin. Energen may choose to allocate additional capital during the year for property acquisitions and/or increased drilling and development activities.

Energen’s development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new proved reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing that increase the number of available drilling locations; changes in the economic or operating environments that allow previously uneconomic locations to be added; technological advances that make reserve locations available for development; successful development of existing proved undeveloped reserve locations that reclassify adjacent probable locations to proved undeveloped reserve locations; increased knowledge of field geology and engineering parameters relative to oil and natural gas reservoirs; and changes in management’s intent to develop certain opportunities.

During the three years ended December 31, 2017, Energen’s development and exploratory efforts have added 312 MMBOE of proved reserves. During the same period, we drilled 405 gross development, exploratory and service wells (including one sidetrack well) and 26 well recompletions and pay-adds. In 2017, Energen’s successful development and exploratory wells and other activities added approximately 115.5 MMBOE of proved reserves; Energen drilled 128 gross development, exploratory and service wells, performed 1 well recompletion and pay-add, and conducted other operational enhancements. Energen’s production totaled 27.8 MMBOE in 2017. In 2018, production is estimated to range from 33.4 MMBOE to 36 MMBOE, with a midpoint of 34.7 MMBOE, including approximately 27.8 MMBOE of estimated production from proved reserves owned at December 31, 2017. Production estimates do not include amounts for potential acquisitions.

Drilling Activity: The following table sets forth the total number of net productive and dry exploratory and development wells drilled:



Years ended December 31,	2017	2016	2015
Development:
Productive	9.6	18.5	50.8
Dry	—	—	—
Total	9.6	18.5	50.8
Exploratory:
Productive	71.9	53.2	98.5
Dry	0.9	—	2.0
Total	72.8	53.2	100.5

Included in the 2017 net wells drilled above are 17 gross (16 net) drilled but uncompleted wells in the Midland Basin and 13 gross (12 net) drilled but uncompleted wells in the Delaware Basin, all of which we plan to complete in 2018. Included in the 2016 net wells drilled above are 42 gross (41 net) drilled but uncompleted wells in the Midland Basin and 17 gross (17 net) drilled but uncompleted wells in the Delaware Basin, all of which we completed in 2017. Included in the 2015 net wells drilled above are 2 gross (2 net) drilled but uncompleted wells in the Midland Basin, which we completed in 2017. As of December

31, 2017, Energen was participating in the drilling of 4 gross (4 net) development and 9 gross (5 net) exploratory wells. In addition to the development wells drilled, Energen drilled 10.0, 3.0 and 12.9 net service wells during 2017, 2016 and 2015, respectively. Energen had no gross service wells in process as of December 31, 2017.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2017, and developed and undeveloped acreage as of the latest practicable date prior to year end:



	Gross	Net
Oil wells	4,987	3,425
Gas wells	131	22
Developed acreage	333,631	230,545
Undeveloped acreage	67,574	35,707

There were no wells with multiple completions at December 31, 2017. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Texas and New Mexico.

Concentration of Credit Risk: Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil, natural gas liquids and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect Energen’s overall exposure to credit risk, either positively or negatively, in that our oil, natural gas liquids and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest purchasers of Energen’s oil, natural gas liquids and natural gas, Plains Marketing, LP (Plains) and Shell Trading (US) Company (Shell), accounted for approximately 50 percent and 18 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2017 . Energen’s other purchasers each accounted for less than 7 percent of these accounts receivable as of December 31, 2017 . During the year ended December 31, 2017 , Plains and Shell accounted for approximately 56 percent and 13 percent , respectively, of total revenues from oil, natural gas liquids and natural gas sales. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2017 .

Risk Management: Energen attempts to lower the commodity price risk associated with its oil and natural gas business through the use of swaps and basis swaps. Energen has policies in place to limit hedging to not more than 80 percent of its estimated annual production; however, Energen’s credit facility contains a covenant that operates to limit hedging at a lower threshold in certain circumstances. Energen recognizes all derivatives on the balance sheet and measures all derivatives at fair value.

See the Cautionary Statement Regarding Forward-Looking Statements preceding Item 1, Business, and Item 1A, Risk Factors, for further discussion with respect to price and other risks.


•	Environmental Matters and Climate Change

Various federal, state and local environmental laws and regulations apply to the operations of Energen. Historically, the cost of environmental compliance has not materially affected our financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend and interpret existing laws and regulations. Such law and regulation changes may occur with little prior notification, subject Energen to cost increases, and impose restrictions and limitations on our operations. Examples of law and regulatory changes with the potential to materially impact Energen include, but are not limited to, measures dealing with hydraulic fracturing, emission limits and reporting and the repeal of certain oil and natural gas tax incentives and deductions.

Energen regularly utilizes hydraulic fracturing in its drilling and completion activities. Energen’s first widespread use of hydraulic fracturing occurred during the 1980s in conjunction with the exploration and development of coalbed methane in Alabama’s Black Warrior Basin.

Hydraulic fracturing is a reservoir stimulation technique used throughout the oil and natural gas industry for more than 60 years. After a well has been drilled, hydraulic fracturing is used during the completion process to form small fractures in the target formation through which the oil and/or natural gas can flow. The fractures are created when a water-based fluid is pumped

at a calculated rate and pressure into the crude oil- or natural gas-bearing rock. The fracture fluid is a mixture composed primarily of water and sand or inert ceramic, sand-like grains; it also contains a small percentage of special purpose chemical additives (which are highly diluted-typically less than one percent by volume) that can vary by project. The millimeter-thick cracks or fractures in the target formation are propped open by the sand, thereby allowing the crude oil or natural gas to flow from tight (low permeability) reservoirs into the well bore.

States in which we operate have adopted a variety of well construction, set back, and disclosure regulations limiting how drilling can be performed and requiring various degrees of chemical and water usage disclosure for operators that employ hydraulic fracturing. We are complying with these additional regulations as part of our routine operations and within the normal execution of our business plan. The adoption of additional federal or state regulations, however, could impose significant new costs and challenges. For example, adoption of new hydraulic fracturing permitting requirements could significantly delay or prevent new drilling. Adoption of new regulatory restrictions on the use of hydraulic fracturing could reduce the amount of oil and gas able to be recovered from our proved reserves. The degree to which additional oil and natural gas industry regulation may impact our future operations and results will depend on the extent to which we utilize the regulated activity and whether the geographic locations in which we operate are subject to the new regulation.

Existing federal, state and local environmental laws and regulations also have the potential to increase costs, reduce liquidity, delay operations and otherwise alter business operations. These existing laws and regulations include, but are not limited to, the Clean Air Act; the Clean Water Act; Oil Pollution Prevention: Spill Prevention, Control, and Countermeasure regulations; Toxic Substances Control Act; Resource Conservation and Recovery Act; and the Federal Endangered Species Act. Compliance with these and other environmental laws and regulations is undertaken as part of Energen’s routine operations. Energen does not separately track costs associated with these routine compliance activities.

Climate change, whether arising through natural occurrences or human activities, may have a significant impact upon the operations of Energen. Volatile weather patterns and the resulting environmental impact may adversely affect our results of operations, financial position and cash flows. We are unable to predict the timing or manifestation of climate change or reliably estimate the impact to Energen. However, climate change could affect our operations as follows:


•	sustained increases or decreases to the supply and demand of oil, natural gas liquids and natural gas;


•	potential disruption to third-party facilities to which Energen delivers. Such facilities include third-party oil and gas gathering, transportation, processing and storage facilities and are typically limited in number and geographically concentrated.

During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency regarding the Reef Environmental Site (the Site) in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Because it used Reef Environmental only one time for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.


•	Employees

The Company has approximately 390 employees. Energen believes that its relations with its employees are good.

ITEM 1A. RISK FACTORS

The future success and continued viability of our business, like any venture, is subject to many recognized and unrecognized risks and uncertainties. Such risks and uncertainties could cause actual results to differ materially from those contained in forward-looking statements made in this report or presented elsewhere by management. The following list identifies and briefly summarizes certain risk factors. The list should not be viewed as complete or comprehensive, as the risks below are not the only risks facing Energen. Energen could also be affected by other risks and uncertainties in addition to those described herein. If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected; and such events could impair our ability to implement business plans or complete development activities as scheduled. Further, the trading price of our shares could decline, and shareholders could lose part or all of their investment. In addition, such risks may prevent us from complying with our financial and non-financial covenants and may result in a default under our credit facility or other short-term or long-term debt.

We undertake no obligation to correct or update such risk factors whether as a result of new information, future events or otherwise. These risk factors should be read in conjunction with our disclosure specific to forward-looking statements made elsewhere in this report under the heading “Cautionary Statement Regarding Forward-Looking Statements”.

Risks Related to Our Business

Commodity prices for crude oil and natural gas are volatile, and a substantial reduction in commodity prices could adversely affect our financial condition and results of operations.

Our revenues, cash flows and earnings are influenced predominantly by the amount of oil, natural gas liquids and natural gas we produce, net of the effects of settlements on our derivative commodity instruments, and the prices we receive for production. Oil, natural gas liquids and natural gas are commodities and historical markets for oil, natural gas liquids and natural gas have been volatile, and prices are subject to wide fluctuations in response to changes in supply and demand.

In addition to reducing our revenue, cash flows and earnings, low prices for oil, natural gas liquids and natural gas may adversely affect us in a variety of other ways. For example, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to writedown, as a noncash impairment loss in our statements of income, the carrying value of our proved oil and natural gas properties. Lower commodity prices may also result in a reduction in the amount we are permitted to borrow under our credit facility and adversely impact our ability to meet financial ratios contained in our debt agreements, especially those calculated by reference to the value of our reserves, earnings or cash flows, which could reduce the amount we are permitted to borrow under our credit facility or result in an event of default under our debt agreements. We could also be required to reduce our capital spending on exploration and development, which will adversely affect our ability to replace our reserves and could result in the loss of leasehold. As more fully disclosed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Credit Facility and Working Capital”, the Company discusses its plans regarding liquidity and covenant compliance for 2018.

Approximately 58 percent of our December 31, 2017 proved reserves are oil. As a result, changes in oil prices have a greater impact on our business than changes of comparable magnitude in natural gas prices. Commodity prices for oil, natural gas liquids and natural gas are reflections of supply and demand and are subject to many factors that are beyond our control, including:


•	the domestic and foreign supply of oil, natural gas liquids and natural gas, including the ability of the members of the Organization of the Petroleum Exporting Countries and other exporting countries to agree on and maintain oil price and production controls;


•	the level of consumer demand for oil, natural gas liquids and natural gas;


•	global or regional oil and natural gas inventory levels;


•	the availability, proximity and capacity of transportation facilities and processing facilities;


•	global economic conditions;


•	commodity price disparities between delivery points and applicable index prices;


•	the supply, demand and pricing of alternative sources of energy or fuels and the effects of energy conservation efforts or technological advances in energy consumption;


•	weather conditions;


•	changes in political conditions in major oil and natural gas producing regions; and


•	domestic, local and foreign governmental regulations and taxes.

Our oil and natural gas proved reserves are estimates, and actual future production may vary significantly and may also be negatively impacted by our inability to invest in production on planned timelines.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. Reserve estimation is a subjective process involving the estimation of volumes to be recovered from underground accumulations of oil and natural gas that are unable to be measured in an exact manner. The reserve estimation process is dependent upon and subject to multiple variables and assumptions, including:


•	oil, natural gas liquids and natural gas prices;


•	timing of development expenditures;


•	the quality, quantity and interpretation of available geological, geophysical and engineering data;


•	the geologic characteristics of the reservoirs;


•	future operating costs, property, severance, excise and other taxes and costs; and


•	the effects of compliance with regulatory and contractual requirements.

Additionally, in the event we are unable to fully invest or must alter the timing of our planned investment expenditures, our future revenues, production and proved reserves could be negatively affected.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could impact our expenses or our production volumes.

Drilling involves many risks, including the risk that no commercially productive oil or natural gas reservoirs will be located or economically developed. Our future drilling activities may not be successful and, if unsuccessful, such failure could have a material adverse effect on our future results of operations and financial condition. Anticipated drilling plans and capital expenditures may also be delayed, curtailed or canceled which could result in actual drilling and capital expenditures being substantially different than currently planned, due to:


•	delays resulting from compliance with regulatory or contractual requirements, which may include limitations on hydraulic

fracturing or the emission of greenhouse gases;


•	unexpected or unusual pressure or irregularities in geological formations;


•	unexpected drilling conditions;


•	declines in oil, natural gas liquids or natural gas prices;


•	adverse weather conditions, such as tornadoes, lightning, flooding, snow and ice storms;


•	delays in, limited availability of, or cost to obtain personnel and equipment necessary to complete our drilling, completion and operating activities;


•	equipment or facility failures and accidents or malfunctions resulting in blowouts, fires, explosions, uncontrollable flows of oil, natural gas or well fluids, surface cratering and other events;


•	title related issues;


•	fracture stimulation failures;


•	restricted access to land for drilling;


•	reductions in availability of financing at acceptable rates;


•	strategic changes implemented by management; and


•	limitations in the market for oil, natural gas liquids and natural gas.

While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involve greater risks of dry holes or failure to find and exploit commercially productive quantities of oil and natural gas. We expect to continue to experience exploration and abandonment expense in 2018 and future years.

Our concentration of producing properties in the Permian Basin of west Texas and New Mexico makes us vulnerable to risks associated with operating in limited geographic areas.

At December 31, 2017, primarily all of our total estimated proved reserves were attributable to properties located in the Permian Basin of west Texas and New Mexico. As a result of this geographic concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by:


•	local, state and federal governmental regulation;


•	processing or transportation capacity constraints;


•	market limitations;


•	water shortages, including restrictions on water usage or other drought related conditions; or


•	interruption of the processing or transportation of oil, natural gas liquids or natural gas.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

Certain of the Company’s acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

Our industry is highly competitive which makes it challenging for us to acquire properties to replace our proved oil and natural gas reserves, market oil and natural gas and locate and secure qualified personnel.

We operate in a highly competitive environment for acquiring properties to replace our proved oil and natural gas reserves, marketing oil and natural gas and locating and securing qualified personnel. Many of our current and potential competitors may possess greater financial, technical and personnel resources than we do. Those competitors may be willing to pay more for exploratory prospects and productive oil and natural gas properties, as well as for trained personnel. Our ability to acquire properties and to find and develop proved reserves in the future will depend on our ability to evaluate and select suitable properties and to execute transactions in an intensely competitive environment. Our failure to acquire properties, market oil and natural gas and secure trained personnel could have a material adverse effect on our production, revenues and results of operations.

Our business is capital intensive, and we may not be able to obtain the needed capital, financing, or refinancing of our current indebtedness on satisfactory terms or at all.

Our exploration, development and acquisition activities are capital intensive and constitute the primary use of our capital resources. We make and expect to continue to make significant capital expenditures for the exploration, development and acquisition of oil, natural gas liquids and natural gas reserves. We have historically funded our capital expenditures through cash flows from operations, our credit facility or other borrowings, debt and equity markets and property sales. We expect that we will continue to fund a portion of our capital expenditures with borrowings under our credit facility, from the proceeds of debt and equity issuances and from proceeds of property sales. However, adverse changes in the commodity price environment or industry conditions may result in a lack of access to capital on attractive terms or at all. Thus, no assurance can be given that we will be able to access either the debt or equity capital markets, or be able to sell properties for attractive prices, to repay any such future borrowings.

If our borrowing capacity decreases, for any reason, we may have limited ability to obtain the capital necessary to support our future operations. If we are unable to obtain necessary financing with appropriate terms, we could experience a decline in our operations. Specifically, a failure to secure additional financing, or necessary refinancing, could result in a reduction of our operations relating to the development of future prospects, which in turn could lead to a decline in our proved oil and natural gas reserves and could adversely affect our future production, revenues and results of operations. Further, we could realize a loss of acreage through lease expirations, and we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

The terms of our credit facility limit the amount we can borrow to a borrowing base amount which is determined by our lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria including commodity price outlook. The borrowing base amount is subject to redetermination semi-annually on April 1 and October 1 of each year and for event-driven unscheduled redeterminations. On April 13, 2016, the borrowing base and aggregate commitments were reduced to $1.05 billion in association with the semi-annual redetermination required under the agreement. On October 25, 2016, the borrowing base was reaffirmed with no changes. On April 21, 2017, the borrowing base was increased to $1.4 billion . The aggregate commitments under the credit facility did not change and remained at $1.05 billion . On November 9, 2017, the borrowing base was increased to $1.7 billion . The aggregate commitments under the credit facility did not change and remained at $1.05 billion . As of December 31, 2017, the Company had $255 million outstanding under its revolving credit facility. A lowering of our borrowing base could require us to immediately repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral, if available. If our borrowing base decreases, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed to fund our capital expenditures, our ability to access the capital markets may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.

We are also subject to financial and non-financial covenants under the terms of our credit facility. The financial covenants in our credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other noncash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0. As of December 31, 2017, we were in compliance with our covenants and expect to maintain compliance during 2018. However, in future periods, factors, including those outside of our control, may prevent us from maintaining compliance with the financial and non-financial covenants, including our total debt to EBITDAX covenant. Such factors may include commodity price declines, lack of liquidity in property and capital markets and our continuing ability to execute on our business plan. In the event that we are unable to remain in compliance with our financial and non-financial covenants, we would seek covenant relief at a scheduled redetermination date or at an interim date, as appropriate. However, no assurances can be given with respect to such relief. If any such covenant violations are not waived by the lenders such violation would result in an event of default that could trigger acceleration of payment of the amounts outstanding under our credit facility and long-term note agreements. Additionally, the lenders could refuse to make additional loans under the credit facility, take possession of any collateral, and exercise other remedies or rights that may be available to them, all of which could have a material adverse effect on the business and financial condition of the Company. As more fully disclosed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Credit Facility and Working Capital”, the Company discusses its plans regarding liquidity and covenant compliance for 2018.

In 2016 we discontinued dividend payments and, therefore, only appreciation in the price of our common stock will provide a return to our stockholders.

Although we have paid cash dividends on our common stock in the past, in February 2016 our board of directors announced the discontinuance of dividend payments. We currently intend to retain future earnings and other cash resources, if any, for the operation and development of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on our results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other considerations that our board of directors deems relevant.

The nature of our operations involves many operational risks including the risk of personal injury, property damage and environmental damage, and our insurance policies do not cover all such risks.

Inherent in our oil and natural gas production activities are a variety of hazards and operational risks, including but not limited to:


•	pipeline and storage leaks, ruptures and spills;


•	equipment malfunctions and mechanical failures;


•	fires and explosions;


•	well blowouts, explosions and cratering;


•	uncontrollable flows of oil, natural gas or well fluids;


•	vandalism;


•	pollution;


•	releases of toxic gases;


•	adverse weather conditions or natural disasters; and


•	soil, surface and water or groundwater contamination from petroleum constituents, hydraulic fracturing fluid, or produced water.

Such events could result in loss of human life, significant damage to or destruction of property, environmental pollution or other damage, impairment or suspension of our operations, repair and remediation costs, regulatory investigations and penalties or lawsuits and other substantial financial losses. Furthermore, our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including those noted above. Additionally, the location of certain of our pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks and losses; and the insurance coverages are subject to retention levels and coverage limits. We may elect not to obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Furthermore, we could be subject to the credit risk of our insurers if we make a claim under our insurance policies. There is no guarantee that we will be able to obtain or maintain our insurance in the future at rates we deem economical and that the insurance we may desire will be offered by insurers. Losses and liabilities arising from uninsured or under-insured events or insurer insolvency, in the event of a claim, could materially and adversely affect our business, financial condition or results of operations.

We are subject to extensive regulation, including numerous federal, state and local laws and regulations as well as legislation and regulations restricting the emissions of “greenhouse gases” that may require significant expenditures or impose significant restrictions on our operations.

We are subject to extensive federal, state and local regulation which significantly influences our operations. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations. Such changes can subject us to significant tax or increased expenditures and can impose significant restrictions and limitations on our operations. Noncompliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other liabilities. Furthermore, we may incur significant costs to remain in compliance with or to return to compliance with applicable regulations if they are revised or reinterpreted or if governmental policies or laws change related to our operations.

If additional federal, state or local regulations or restrictions are adopted in the areas we operate or plan to operate, we may incur significant costs to comply with the requirements, experience delays or have to curtail our exploration, development, or production activities. Additionally, such restrictions could reduce the amount of oil and gas that we are able to recover from our proved reserves.

While the subject of climate change appeared to be a federal regulatory priority in years past, efforts at the federal level are currently focused on rolling back or repealing many environmental regulations including those related to climate change. However, many state and local governments remain focused on climate change, adopting new regulations to control emissions and otherwise legislate efforts to reduce climate change. If federal regulatory priorities shift and additional federal regulations are adopted, or if state and local legislation or regulatory programs to reduce emissions of greenhouse gases are adopted, it could require us to incur increased operating costs, such as those for purchasing and operating emissions control systems, acquiring emissions allowances or complying with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming and using oil and natural gas, and thereby negatively impact the demand for the oil, natural gas liquids and natural gas we produce. Consequently, legislation and regulatory programs related to greenhouse gases could adversely affect our production, revenues and results of operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect our production.

Energen regularly utilizes hydraulic fracturing in its drilling and completion activities, and hydraulic fracturing is a common practice that is used in the oil and gas industry to stimulate production of hydrocarbons from tight (low permeability) formations. After a well has been drilled, hydraulic fracturing is used during the completion process to form small fractures in the target formation through which the oil, natural gas liquids or natural gas can flow. The fractures are created when a water-based fluid is pumped at a calculated rate and pressure into the crude oil- or natural gas-bearing rock. The fracture fluid is a mixture composed primarily of water and sand or inert ceramic, sand-like grains; it also contains a small percentage of special purpose chemical additives (which are highly diluted-typically less than one percent by volume) that can vary by project. The millimeter-thick cracks or fractures in the target formation are propped open by the sand, thereby allowing the crude oil or natural gas to flow from tight reservoirs into the well bore.

The hydraulic fracturing process is typically regulated by state oil and gas commissions. Texas and New Mexico, two states in which we operate, have adopted, and other states have considered adopting, regulations that could impose new or stricter permitting, disclosure and well construction requirements on companies that perform hydraulic fracturing. Consideration and efforts to regulate hydraulic fracturing by local, state and federal authorities continue and local land use restrictions, such as county and city ordinances, may also restrict or prohibit any type of drilling or hydraulic fracturing. Federal legislation governing hydraulic fracturing activities has been somewhat limited. However, under the Safe Drinking Water Act’s Underground Injection Control Program, the EPA has assumed regulatory authority of hydraulic fracturing involving diesel additives and issued revised permitting guidance in February 2014 requiring facilities to obtain permits to use diesel additives in hydraulic fracturing activities. Legislation intended to provide for federal regulation of hydraulic fracturing and require disclosure of the chemicals used has been introduced and considered by the U.S. Congress. In December 2016, the EPA issued its final report on the relationship between hydraulic fracturing and drinking water resources and no further federal regulatory efforts have been undertaken since the issuance of that report. Continuing efforts to regulate hydraulic fracturing are most likely to be at the state and local government level. If federal restrictions, or additional state or local restrictions in the areas we operate, or plan to operate, are adopted, we may incur significant costs to comply with the requirements, experience delays or have to curtail our exploration, development, or production activities. Additionally, such restrictions could reduce the amount of oil and gas that we are able to recover from our proved reserves.

Our operations are dependent on the availability, use and disposal of water; and restrictions on our ability to acquire or dispose of water could cause us to incur substantial costs in the acquisition, usage and disposal of water.

Water is a key component of both the drilling and hydraulic fracturing processes. Historically, we have been able to obtain water from various local sources for use in our operations. Over the last decade, Texas has experienced periods of severe drought conditions that have persisted for several years. Local water districts may restrict the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply during drought conditions. If we are unable to obtain water to use in our operations from local sources, we may have to incur substantial costs to produce oil and natural gas and it may make it uneconomical to produce in that area. Our drilling procedures produce water of which we must dispose. We could be unable to dispose of our wastewater or face increased costs and procedures for disposal as a result of changes in federal, state or local legislation governing the disposal of drilling wastewater.

We periodically evaluate our proved and unproved oil and natural gas properties for impairment and could be required to recognize non-cash charges in our statements of income in future periods. If commodity prices for oil, natural gas liquids or natural gas decline or our drilling efforts are unsuccessful, we may be required to writedown the carrying values of certain oil and natural gas properties.

We periodically review the carrying value of our proved and unproved oil and natural gas properties for possible impairment on a field-by-field basis. We monitor our oil and natural gas properties as well as the market and business environments in which we operate and make assessments about events that could result in potential impairment issues, which include, but are not limited to, downward commodity price trends, unanticipated increased operating costs and lower than expected production performance. If a material event occurs, we perform an evaluation to determine whether the asset is impaired. If the undiscounted net future cash flows determined by such evaluations are insufficient to fully recover the cost invested in the respective project, we will record an impairment loss in our statements of income. We recorded $1.7 million , $220.7 million and $1.3 billion of impairments during 2017, 2016 and 2015, respectively.

We are exposed to counterparty credit risk as a result of our concentrated customer base and to the risks associated with other companies with whom we do business experiencing financial distress.

Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil, natural gas liquids and natural gas to a small number of energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to a limited number of customers in the energy marketing industry has the potential to adversely affect our overall exposure to credit risk based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. We consider the credit quality of our customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent company guarantee.

In addition, we rely on other working interest owners in our wells to pay their proportionate share of costs and on oilfield service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A decline in the commodity price environment may result in a material adverse impact on the liquidity and financial position of the companies with whom we do business, resulting in delays in payment of, or non-payment of, amounts owing to us and similar impacts. These events could have an adverse impact on our financial condition, results of operations and cash flows.

We are subject to financing and interest rate exposure risks. Volatility in global financial markets, negative operating results, certain strategic business decisions, or other matters resulting in a downgrade in, or a negative outlook with respect to, our credit ratings could negatively impact our cost of and our ability to access capital for future development and working capital needs.

We rely on access to credit markets, and turmoil or volatility in the global financial markets could lead to a contraction in credit availability and negatively impact our ability to finance our operations. Global financial market turmoil, as has been experienced in the last decade, could materially affect our operations, liquidity and financial condition through the adverse impacts such turmoil can have on the debt and equity capital markets. Market volatility and credit market disruption may severely limit credit availability, and issuer credit ratings can change rapidly. A significant reduction in cash flows from operations or the availability of credit could limit our ability to pursue acquisition opportunities or reduce cash flow used for drilling which could materially and adversely affect our ability to achieve our planned growth and operating results.

The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders and Energen. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring,

acquisition and disposition transactions involving Energen may negatively impact market and rating agency considerations regarding the credit of Energen.

Our derivative risk management activities may limit our potential gains and involve other risks that could result in financial losses.

Although we make use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, natural gas liquids and natural gas prices could materially affect our financial position, results of operations and cash flows. Furthermore, such risk mitigation activities may cause our financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not been implemented. The changes in the fair market value of our derivative contracts as reported in our consolidated statements of income may result in significant non-cash gains or losses.

The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality and that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options, collars and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave us financially exposed to our counterparties and result in material adverse financial consequences to Energen. The adverse effect could be increased if the adverse event was widespread enough to move market prices against our position.

Derivatives reform legislation and associated regulation could negatively impact our ability to use derivative instruments as part of our risk management activities.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) established federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets by the Commodities Futures Trading Commission (CFTC) and the SEC. The CFTC and the SEC have adopted, or are in the process of adopting, rules and regulations covering, among other derivative transactions, transactions linked to crude oil and natural gas prices. Although the CFTC has adopted some final regulations, other regulations applicable to derivative transactions in which Energen engages have not been finally adopted or implemented, and we cannot predict the timing of adoption of final regulations.

The CFTC issued proposed regulations to set position limits for certain futures and options contracts in the major energy markets and for swaps that are their economic equivalents in October 2011. The CFTC’s initial regulations on position limits were vacated by the U.S. District Court for the District of Columbia in 2012, and the CFTC proposed new position limits in November 2013. The CFTC modified its commodity position limits proposal in May 2016 and the revised position limit regulations have not yet been adopted; however, the rules as proposed place limits on certain physical commodity swap contracts, subject to exceptions for bona fide hedging contracts. Until such time as the regulations are finalized, we cannot ascertain the impact of such regulations on our derivative activities.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also may require Energen, in connection with covered derivative activities, to comply with certain clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements, although the application of these provisions to us is uncertain at this time. Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as dealers, may change the cost and availability of our future derivative arrangements (including through requirements to post collateral which could adversely affect Energen’s available liquidity). The changes in the regulation of swaps may result in certain market participants deciding to curtail or stop engaging in derivative activities. If we reduce our use of derivatives as a result of the Dodd Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and our results of operations. Any of these consequences could have a material adverse effect on our financial condition and results of operations.

Our operations depend on the use of third-party facilities, and an interruption of our ability to utilize these facilities may adversely affect our financial condition and results of operations.

Energen delivers to third-party facilities. These facilities include third-party oil and natural gas gathering, transportation, processing and storage facilities. Energen relies on such facilities for access to market for our oil, natural gas liquids and natural gas production. Such facilities are typically limited in number and geographically concentrated. A lack of available capacity on these facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties for Energen. An

extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act, maintenance or otherwise could have an adverse effect on our revenues and results of operations.

The success of our future operations is dependent on our future drilling activities and our ability to economically develop our oil, natural gas liquids and natural gas reserves; and our expectations regarding future drilling and development activities are subject to uncertainties that could significantly alter the occurrence or timing of such activities, as they are expected to be realized over multiple years.

We have identified drilling locations and prospects for future drilling, including development and exploratory drilling activities. Our ability to successfully and economically drill and develop these locations depends on a number of factors, including:


•	prices of oil, natural gas liquids and natural gas;


•	current laws or regulations or changes in the laws or regulations in or affecting the identified and prospective locations;


•	the availability and cost of capital;


•	seasonal and other weather conditions;


•	regulatory approvals;


•	negotiation of agreements with third parties;


•	access to and availability of required equipment, supplies and personnel; and


•	drilling results.

Because of the factors noted above, we cannot provide any guarantee regarding the timing or success of future drilling activities; and our actual drilling activities may materially differ from our current expectations, including potential delays, curtailment or cancellation of anticipated drilling plans and capital expenditures.

Energen has limited control over activities on properties which we do not operate, which could reduce our production and revenues.

Energen operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and, in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. For properties we do not operate, we have limited ability to control the operation or future development of the properties or the amount of capital expenditures that we are required to fund with respect to them. An operator’s failure to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in our best interest could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others is dependent on a number of factors, including the operator's timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Our dependence on the operator and other working interest owners for these projects and our limited ability to control the operation and future development of these properties could negatively affect the realization of our expected returns on capital in drilling or acquisition activities and could lead to unexpected costs in the future.

Our business could be negatively impacted by security threats, including cybersecurity threats and related disruptions.

We face a variety of security threats, including cybersecurity threats to access sensitive information or render data or systems unusable, threats to the security of our facilities and infrastructure or those of third parties, including processing plants and pipelines, and threats from terrorist acts. Current procedures and controls may not be sufficient to prevent security breaches from occurring, and we could have to implement additional procedures and controls to mitigate the effects of potential breaches and monitor for potential security threats resulting in increased capital and operating costs. In the event of a security breach, losses of sensitive information, critical infrastructure or capabilities essential to our operations could occur and could have a material adverse effect on our reputation, operations, financial position and results of operations. Cybersecurity attacks are sophisticated and prevalent and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, other electronic security breaches that could cause disruptions in critical systems, unauthorized release of confidential information and data corruption. As we rely on our information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of our business and day-to-day operations, such attacks could lead to a material disruption in our business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, financial losses, loss of business, potential liability and damage our reputation.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

The corporate headquarters of Energen and Energen Resources are located in leased office space in Birmingham, Alabama. See the discussion under Item 1, Business, for further information related to Energen’s business operations. Information concerning Energen’s production and proved reserves is summarized in the table below and included in Note 20, Oil and Natural Gas Operations (Unaudited), in the Notes to Financial Statements. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the future outlook and expectations for Energen and additional information regarding production, revenue and production costs.

Energen focuses on increasing its production and proved reserves through the development and exploration of onshore North American oil and natural gas properties. Energen maintains a district office in Midland, Texas.

Energen’s major area of operation is in the Permian Basin as highlighted on the above map.

The following table sets forth the production volumes, proved reserves and proved reserves-to-production ratio by area:



	Year ended
	December 31, 2017	December 31, 2017	December 31, 2017
	Production Volumes (MBOE)	Proved Reserves (MBOE)	Proved Reserves-to-Production Ratio
Permian Basin
Midland Basin	15,491	293,797	18.97 years
Delaware Basin	9,360	108,086	11.55 years
Central Basin Platform	2,870	41,137	14.33 years
Other	73	1,018	13.95 years
Total	27,794	444,038	15.98 years

The following table sets forth proved reserves by area as of December 31, 2017:



	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin
Midland Basin	165,816	64,566	380,493	293,797
Delaware Basin	55,637	22,742	178,240	108,086
Central Basin Platform	35,293	3,438	14,433	41,137
Other	264	33	4,323	1,018
Total	257,010	90,779	577,489	444,038

See Note 20, Oil and Natural Gas Operations (Unaudited), in the Notes to Financial Statements for the changes to proved reserves during the years ended December 31, 2017, 2016 and 2015 of oil, natural gas liquids and natural gas.

The following table sets forth proved developed reserves by area as of December 31, 2017:



	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin
Midland Basin	72,112	34,823	208,376	141,665
Delaware Basin	36,238	14,588	115,484	70,073
Central Basin Platform	35,293	3,438	14,433	41,137
Other	264	33	4,323	1,018
Total	143,907	52,882	342,616	253,893

The following table sets forth proved undeveloped reserves by area as of December 31, 2017:



	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin
Midland Basin	93,704	29,743	172,117	152,132
Delaware Basin	19,399	8,154	62,756	38,013
Total	113,103	37,897	234,873	190,145

The following table sets forth the reconciliation of proved undeveloped reserves:



Year ended December 31, 2017	Total MMBOE
Balance at beginning of period	154.2
Undeveloped reserves transferred to developed reserves	(18.0)
Revisions	22.7
Extensions and discoveries	31.2
Balance at end of period	190.1

Proved undeveloped reserves transferred to proved developed reserves reflect capital expenditures of approximately $107 million during the year ended December 31, 2017 in development of previously proved undeveloped reserves. Proved undeveloped reserves additions included proved undeveloped reserve locations one offset away from producing wells and proved undeveloped reserve locations that are more than one offset away from producing wells using reliable technology and where our geologic interpretation and experience indicate the reservoirs are continuous across those locations. The technologies associated with these additions to

proved reserve estimates included analysis of well production data, geophysical data, wireline data, core data and interpretation of zonal analysis. Revisions total 22.7 MMBOE and include positive revisions of 17.6 MMBOE from extending lateral lengths of certain locations and 9.2 MMBOE due to changes in proved type curves due to improved well performance partially offset by negative revisions of 4.6 MMBOE of proved undeveloped reserves that will no longer be developed in the five-year time horizon.

Estimated proved reserves as of December 31, 2017 are based upon studies for each of our properties prepared by Company engineers and audited by Ryder Scott Company, L.P. (Ryder Scott), independent oil and gas reservoir engineers. Calculations were prepared using geological and engineering methods widely used and referred to by professionals in the industry and in accordance with SEC guidelines.

A Senior Vice President at Ryder Scott is the technical person primarily responsible for overseeing the audit of the reserves. The Senior Vice President has a Bachelor of Science degree in Mechanical Engineering and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has been employed by Ryder Scott since 1982 and also serves as chief technical advisor of unconventional reserves evaluation. Energen Resources’ Vice President – Reservoir Engineering is the technical person primarily responsible for overseeing reserves on behalf of Energen. His background includes a Bachelor of Science degree in Civil Engineering and membership in the Society of Petroleum Engineers. He is a registered Professional Engineer in the state of Louisiana with more than 35 years of experience evaluating oil and natural gas properties and estimating reserves.

Energen relies upon certain internal controls when preparing its reserve estimations. These internal controls include review by the reservoir engineering managers to ensure the correct reserve methodology has been applied for each specific property and that the reserves are properly categorized in accordance with SEC guidelines. The reservoir engineering managers also affirm the accuracy of the data used in the reserve and associated rate forecast, provide a review of the procedures used to input pricing data and provide a review of the working and net revenue interest factors to ensure that factors are adequately reflected in the engineering analysis.

Net production forecasts are compared to historical sales volumes to check for reasonableness, and operating costs and severance taxes calculated in the reserve report are compared to historical accounting data to help ensure proper cost estimates are used. A reserve table is generated comparing the previous year’s reserves to current year reserve estimates to determine variances. This table is reviewed by the Vice President – Reservoir Engineering and the Chief Operating Officer of Energen Resources. Revisions and additions are investigated and explained.

Reserve estimates of proved reserves are sent to independent reservoir engineers for audit and verification. For 2017, approximately 99 percent of all proved reserves were audited by the independent reservoir engineers which audit engineering procedures, check the reserve estimates for reasonableness and check that the reserves are properly classified.

The following table sets forth the standard pressure base in pounds-force per square inch absolute (psia) for the significant states in which Energen has wells:



Texas		14.65 psia
New Mexico		15.025 psia

The following table sets forth the total net productive oil and natural gas wells by area as of December 31, 2017 , and developed and undeveloped acreage as of the latest practicable date prior to year-end:



	Gross Wells	Net Wells	Net Developed Acreage	Net Undeveloped Acreage
Permian Basin
Midland Basin	1,213	1,112	85,904	8,903
Delaware Basin	324	204	43,016	18,892
Central Basin Platform and other	3,498	2,124	79,102	1,159
Other	83	7	22,523	6,753
Total	5,118	3,447	230,545	35,707

The following table sets forth expiration dates for gross and net undeveloped acreage at year end as of December 31, 2017 :



	Years ending December 31,
	2018		2019		2020		Thereafter
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian
Midland Basin	6,545	3,057	2,092	2,415	3,672	1,882	2,514	1,549
Delaware Basin	11,984	7,240	9,335	4,696	8,791	3,795	4,140	3,161
Central Basin Platform and other	417	93	—	—	—	—	2,898	1,066
Other*	—	—	—	—	116	14	15,070	6,739
Total	18,946	10,390	11,427	7,111	12,579	5,691	24,622	12,515

*Other includes a total of 15,186 gross (6,753 net) acreages principally located in Alabama, Wyoming, Kentucky, Louisiana and Texas, where Energen does not currently have plans for development.

In the ordinary course of business based on our evaluation of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

At December 31, 2017, Energen had approximately 444 MMBOE total proved reserves which included 190.1 MMBOE of proved undeveloped reserves. We had approximately 37.5 MMBOE, or 19.7 percent, of our proved undeveloped reserves on leased acreage which is not held by production. The continuous development provisions of these leases extend the primary terms upon the satisfaction of certain conditions. These provisions generally require at least one well be drilled on such leases prior to the expiration of the primary term and that subsequent wells be drilled within a time period that is specific to each lease but ranges from 60 days to 180 days. Once a lease is fully developed, it remains in effect as long as production is maintained from the lease. Our drilling plans provide for the development of these proved undeveloped reserves prior to the expiration of the initial primary term or under the extended primary term as provided for under the continuous development provisions of our lease agreements.

ITEM 3. LEGAL PROCEEDINGS

Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Various pending or threatened legal proceedings are in progress currently.

On September 12, 2017, Energen filed a complaint for declaratory and injunctive relief against Corvex Management LP (Corvex), at the time a more than ten percent shareholder of Energen. The complaint was filed in the Circuit Court of Jefferson County, Alabama. Corvex had made clear that it believed it was entitled to call a special meeting of Energen shareholders for the purposes of expanding the Company’s Board of Directors and electing directors to fill the vacancies created by such expansion. On October 31, 2017, the Court issued a declaratory judgment order affirming Energen’s position that Energen’s certificate of incorporation and related provisions of the laws of Alabama grant to the Energen Board the exclusive right to determine the number of directors within a range of 9 to 15 and to fill any vacancies resulting from an increase in the number of directors. Corvex filed a Notice of Appeal with the Circuit Court of Jefferson County, Alabama on November 13, 2017, appealing the Court’s order to the Alabama Supreme Court. Energen is contesting the appeal and arguing in favor of upholding the Court’s order.

See Note 12, Commitments and Contingencies, in the Notes to Financial Statements for further discussion with respect to legal proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

None

EXECUTIVE OFFICERS OF THE REGISTRANT



Name	Age	Position (1)
James T. McManus, II	59	Chairman, Chief Executive Officer and President of Energen (2)
Charles W. Porter, Jr.	53	Vice President, Chief Financial Officer and Treasurer of Energen (3)
John S. Richardson	60	President and Chief Operating Officer of Energen Resources (4)
John K. Molen	65	Vice President, General Counsel and Secretary of Energen (5)
David A. Godsey	63	Senior Vice President – Exploration and Geology of Energen Resources (6)
Davis E. Richards	62	Senior Vice President – Operations of Energen Resources (7)
Russell E. Lynch, Jr.	44	Vice President and Controller of Energen (8)

Notes :

(1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years except for Mr. Molen and Mr. Richards. Officers serve at the pleasure of the Board of Directors.

(2) Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997. He was elected President and Chief Operating Officer of Energen effective January 1, 2006 and Chief Executive Officer of Energen and each of its subsidiaries effective July 1, 2007. He was elected Chairman of the Board of Energen and each of its subsidiaries effective January 1, 2008. Mr. McManus serves as a Director of Energen and each of its subsidiaries.

(3) Mr. Porter has been employed by the Company in various financial capacities since 1989. He was elected Controller of Energen Resources in 1998. In 2001, he was elected Vice President – Finance of Energen Resources. He was elected Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries effective January 1, 2007.

(4) Mr. Richardson has been employed by the Company in various capacities since 1985. He was elected Vice President – Acquisitions and Engineering of Energen Resources in 1997. He was elected Executive Vice President and Chief Operating Officer of Energen Resources effective January 1, 2006. He was elected President and Chief Operating Officer of Energen Resources effective January 23, 2008.

(5) Mr. Molen was employed by the Company in June 2017 as Vice President, Associate General Counsel and Assistant Secretary of Energen and Energen Resources. He was elected Vice President, General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2018. He was an associate from 1978 to 1984 and a partner from 1984 to May 31, 2017 with the law firm of Bradley Arant Boult Cummings LLP.

(6) Mr. Godsey was employed by the Company in December 2012 as Senior Vice President – Exploration and Geology of Energen Resources. He served as Geoscience Manager Permian Basin for Cheasapeake Energy from April 2003 to December 2012. He also served from December 1999 to April 2003 as Project Geologist for EOG Resources, Inc.

(7) Mr. Richards was employed by the Company in October 2013 as Vice President – Drilling and Completions of Energen Resources. He was elected Senior Vice President – Operations of Energen Resources effective January 1, 2016. He became an executive officer of Energen effective January 1, 2018. He served in various capacities with Sonat Exploration Company from 1977 to 1999 and then with El Paso Exploration and Production Company from 1999 until 2012, with his last position being General Manager of Drilling. He also served as General Manager of Completions for EP Energy Corporation’s domestic operations from May 2012 until October 2013.

(8) Mr. Lynch has been employed by the Company in various capacities since 2001. He was elected Vice President and Controller of Energen effective January 1, 2009. He was elected Vice President and Controller of Energen Resources effective January 22, 2016.

PART II


ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES



Quarterly Market Prices

Quarter ended	High	Low	Close
March 31, 2016	$42.76	$20.76	$36.59
June 30, 2016	$51.27	$34.03	$48.21
September 30, 2016	$60.00	$43.70	$57.72
December 31, 2016	$64.44	$47.88	$57.67
March 31, 2017	$60.21	$47.95	$54.44
June 30, 2017	$58.96	$46.25	$49.37
September 30, 2017	$55.22	$46.16	$54.68
December 31, 2017	$58.96	$48.59	$57.57

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. At February 13, 2018, there were 3,778 holders of record of Energen common stock.

Dividends

In February 2016, we announced the discontinuance of dividend payments. Accordingly, we do not expect to pay cash dividends on Energen common stock in 2018. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors. Energen may not pay dividends during an event of default, if the payment would result in an event of default or if availability is less than 10 percent of the loan limit under the credit facility.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes information concerning purchases of equity securities by the issuer:



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares that May Yet Be Purchased Under the Plans*
October 1, 2017 - October 31, 2017	—	$	—	—	3,373,161
November 1, 2017 - November 30, 2017	—	—		—	3,373,161
December 1, 2017 - December 31, 2017	—	—		—	3,373,161
Total	—	$	—	—	3,373,161

*By resolution adopted October 22, 2014, the Board of Directors authorized Energen to repurchase up to 3,600,000 shares of Energen common stock. The resolution does not have an expiration date and does not limit Energen’s authorization to acquire shares in connection with tax withholdings and payment of exercise price on stock compensation plans.

PERFORMANCE GRAPH

Energen Corporation — Comparison of Five-Year Cumulative Shareholder Returns

This graph compares the total shareholder returns of Energen, the Standard & Poor’s Composite Stock Index (S&P 500) and the Standard & Poor’s Supercomposite Oil & Gas Exploration & Production Index (S15OILP). The graph assumes $100 invested at the per-share closing price of the common stock on the New York Exchange Composite Tape on December 31, 2012, in the Company and each of the indices. Total shareholder return includes reinvested dividends.



As of December 31,	2012		2013		2014		2015		2016		2017
S&P 500	$	100	$	132	$	150	$	153	$	171	$	208
Energen	$	100	$	158	$	144	$	93	$	130	$	130
S15OILP	$	100	$	129	$	112	$	73	$	97	$	89

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data as set forth below should be read in conjunction with the consolidated financial statements and the Notes to Financial Statements included in this Form 10-K.

SELECTED FINANCIAL AND COMMON STOCK DATA



Years ended December 31, (dollars in thousands, except per share amounts)	2017		2016			2015			2014		2013
STATEMENT OF OPERATIONS
Total revenues	$	961,045	$	532,889		$	878,554		$	1,679,213	$	1,206,293
Income (loss) from continuing operations	$	306,828	$	(167,513	)	$	(945,731	)	$	99,643	$	141,881
Net income (loss)	$	306,828	$	(167,513	)	$	(945,731	)	$	568,032	$	204,554
Diluted earnings per average common share from continuing operations	$	3.14	$	(1.77	)	$	(12.43	)	$	1.36	$	1.96
Diluted earnings per average common share	$	3.14	$	(1.77	)	$	(12.43	)	$	7.75	$	2.82
BALANCE SHEET
Total property, plant and equipment, net	$	4,763,520	$	4,061,552		$	4,350,690		$	5,199,137	$	5,118,088
Total assets	$	5,033,895	$	4,579,823		$	4,611,156		$	6,138,258	$	6,622,212
Long-term debt	$	782,861	$	527,443		$	773,550		$	1,038,563	$	1,093,541
Total shareholders’ equity	$	3,438,457	$	3,120,602		$	2,895,860		$	3,414,604	$	2,858,019
COMMON STOCK DATA
Cash dividends paid per common share	$	—	$	—		$	0.08		$	0.47	$	0.58
Diluted average common shares outstanding (000)	97,707		94,476			76,078			73,275		72,471
Price range:
High	$	60.21	$	64.44		$	77.12		$	90.66	$	89.92
Low	$	46.16	$	20.76		$	39.99		$	53.78	$	44.46
Close	$	57.57	$	57.67		$	40.99		$	63.76	$	70.75

SELECTED BUSINESS DATA



Years ended December 31, (dollars in thousands, except per unit data)	2017			2016			2015			2014		2013
Oil, natural gas liquids and natural gas sales from continuing operations
Oil	$	814,470		$	521,017		$	631,663		$	988,868	$	961,055
Natural gas liquids	98,298			48,652			48,856			110,918		91,407
Natural gas	74,670			51,697			82,742			244,408		203,855
Total	$	987,438		$	621,366		$	763,261		$	1,344,194	$	1,256,317
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	(10,658	)	$	(57,148	)	$	(242,227	)	$	271,200	$	(43,261	)
Natural gas liquids	(9,011		)	(6,868		)	—			287		(652		)
Natural gas	8,910			(7,174		)	(39,525		)	43,958		(3,919		)
Total	$	(10,759	)	$	(71,190	)	$	(281,752	)	$	315,445	$	(47,832	)
Closed gains (losses) on derivative instruments
Oil	$	(11,364	)	$	(17,701	)	$	346,404		$	4,377	$	(52,694	)
Natural gas liquids	(7,780		)	—			—			6,218		10,795
Natural gas	3,510			414			50,641			8,979		39,707
Total	$	(15,634	)	$	(17,287	)	$	397,045		$	19,574	$	(2,192	)
Total revenues	$	961,045		$	532,889		$	878,554		$	1,679,213	$	1,206,293
Production volumes from continuing operations
Oil (MBbl)	16,951			13,213			14,023			11,814		10,364
Natural gas liquids (MMgal)	220.7			163.5			170.7			172.3		135.8
Natural gas (MMcf)	33,528			27,204			35,604			58,602		58,104
Production volumes from continuing operations (MBOE)	27,794			21,639			24,022			25,684		23,281
Total production volumes (MBOE)	27,794			21,639			24,022			25,849		25,362
Proved reserves
Oil (MBbl)	257,010			199,575			210,691			181,227		164,870
Natural gas liquids (MBbl)	90,779			58,046			71,713			73,463		63,011
Natural gas (MMcf))	577,489			352,248			433,904			707,926		719,725
Total (MBOE)	444,038			316,329			354,722			372,678		347,835
Costs per BOE from continuing operations
Oil, natural gas liquids and natural gas production expenses	$	6.61		$	7.94		$	9.51		$	10.68	$	11.06
Production and ad valorem taxes	$	2.14		$	1.98		$	2.39		$	3.97	$	4.04
Depreciation, depletion and amortization	$	17.39		$	20.70		$	24.72		$	21.36	$	19.45
Exploration expense	$	0.36		$	0.25		$	0.62		$	1.09	$	0.60
General and administrative expense	$	3.05		$	4.42		$	6.21		$	4.75	$	4.89
Capital expenditures (including acquisitions)	$	1,189,342		$	582,898		$	1,114,808		$	1,451,951	$	1,120,753


ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW OF BUSINESS

Energen is focused on increasing its oil, natural gas liquids and natural gas production and proved reserves through its active development and/or exploratory programs in the Permian Basin. The Company seeks to expand its footprint primarily through acquisitions of proved properties and unproved leasehold within areas of existing operations. All oil, natural gas liquids and natural gas production is sold to third parties. Energen operates properties for its own interest and that of its joint interest owners. This role includes overall project management and day-to-day decision-making relative to project operations.

FINANCIAL AND OPERATING PERFORMANCE

Overview of 2017 Results and Activities

Key results during 2017 were as follows:


•	realized higher commodity prices, including a 21.9 percent increase in oil prices to $48.05 per barrel and a 17.4 percent increase in natural gas prices to $2.23 per Mcf;


•	produced 27,794 MBOE in the current year as compared to 21,639 MBOE in the prior year, which included production in the prior year associated with sold properties of 1,658 MBOE;


•	recognized per unit declines of 31 percent and 16.8 percent in general and administrative (G&A) expense and oil, natural gas liquids and natural gas production expense, respectively; and


•	completed an estimated $273.3 million in various purchases and renewals of unproved leasehold in the Permian Basin, including approximately $217.4 million in the Delaware Basin and approximately $36.9 million in the Midland Basin for unproved leasehold and $19.0 million for mineral purchases primarily in the Delaware Basin.

Year ended December 31, 2017 vs year ended December 31, 2016

Energen’s net income for the year ended December 31, 2017 totaled $306.8 million ( $3.14 per diluted share) compared to the year ended December 31, 2016 net loss of $167.5 million ( $1.77 per diluted share). This change in net income was primarily the result of:


•	income tax benefit from the 2017 enactment of the Tax Cuts and Jobs Act (approximately $240 million);


•	increased realized oil and natural gas commodity prices (approximately $122 million after-tax);


•	non-cash impairments in 2016 on certain Permian Basin oil properties primarily in the Central Basin Platform (approximately $120.4 million after-tax) and the Delaware Basin (approximately $13.7 million after-tax);


•	higher oil, natural gas liquids and natural gas production volumes (approximately $114 million after-tax);


•	increased year-over-year after-tax gains of $39 million on open derivatives (resulting from an after-tax $6.9 million non-cash loss on open derivatives for 2017 and an after-tax $45.9 million non-cash loss on open derivatives for 2016);


•	decreased G&A expense (approximately $7 million after-tax);


•	non-cash impairments in 2016 on certain properties in the San Juan Basin (approximately $4.8 million after-tax);


•	gain in December 2017 from a lawsuit settlement over certain leasehold interests (approximately $4.1 million after-tax);


•	unproved leasehold writedowns in 2016 primarily on Permian Basin properties in the Delaware Basin and Central Basin Platform (approximately $3 million after-tax); and


•	period over period gain on closed derivatives (approximately $1 million after-tax);

partially offset by:


•	gain in 2016 on a series of asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin (approximately $158.4 million after-tax);


•	higher depreciation, depletion and amortization (DD&A) expense (approximately $23 million after-tax);


•	higher production and ad valorem taxes (approximately $11 million after-tax);


•	higher oil, natural gas liquids and natural gas production expense (approximately $8 million after-tax); and


•	increased exploration expense (approximately $3 million after-tax).

Year ended December 31, 2016 vs year ended December 31, 2015

For the year ended December 31, 2016, Energen’s net loss totaled $167.5 million ( $1.77 per diluted share) as compared to a net loss of $945.7 million ( $12.43 per diluted share) in 2015. This change in net loss was primarily the result of:


•	non-cash impairments in 2015 on certain Permian Basin oil properties in the Delaware Basin (approximately $388.3 million after-tax) and in the Central Basin Platform (approximately $310.1 million after-tax);


•	gain in 2016 on a series of asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin (approximately $158.4 million after-tax);


•	lower year-over-year after-tax losses of $135.3 million on open derivatives (resulting from an after-tax $45.9 million non-cash loss on open derivatives for 2016 and an after-tax $181.3 million non-cash loss on open derivatives for 2015);


•	lower depreciation, depletion and amortization (DD&A) expense (approximately $94 million after-tax);


•	non-cash impairments in 2015 on certain held for sale properties in the San Juan Basin (approximately $85.1 million after-tax);


•	lower oil, natural gas liquids and natural gas production expense (approximately $37 million after-tax);


•	decreased general and administrative (G&A) expense (approximately $34 million after-tax);


•	unproved leasehold writedowns in 2015 on San Juan Basin properties (approximately $24.3 million after-tax);


•	additional unproved leasehold writedowns in 2015 primarily on Permian Basin properties in the Delaware Basin (approximately $18.7 million after-tax);


•	lower production and ad valorem taxes (approximately $9 million after-tax);


•	lower exploration expense (approximately $6 million after-tax); and


•	decreased interest expense (approximately $4 million after-tax);

partially offset by:


•	period over period loss on closed derivatives (approximately $267 million after-tax);


•	non-cash impairments on certain Permian Basin oil properties primarily in the Central Basin Platform (approximately $120.4 million after-tax) and the Delaware Basin (approximately $13.7 million after-tax);


•	decreased realized oil and natural gas commodity prices (approximately $55 million after-tax);


•	lower oil, natural gas liquids and natural gas production volumes (approximately $37 million after-tax);


•	gain in 2015 on sale of the majority of our natural gas assets in the San Juan Basin (approximately $17.3 million after tax);


•	non-cash impairments on certain properties in the San Juan Basin (approximately $4.8 million after-tax); and


•	unproved leasehold writedowns primarily on Permian Basin properties in the Delaware Basin and Central Basin Platform (approximately $3 million after-tax).

Results of Operations

The following table summarizes information regarding our production and operating data.



Years ended December 31, (in thousands, except sales price and per unit data)	2017			2016			2015
Operating and production data from operations
Oil, natural gas liquids and natural gas sales
Oil	$	814,470		$	521,017		$	631,663
Natural gas liquids	98,298			48,652			48,856
Natural gas	74,670			51,697			82,742
Total	$	987,438		$	621,366		$	763,261
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	(10,658	)	$	(57,148	)	$	(242,227	)
Natural gas liquids	(9,011		)	(6,868		)	—
Natural gas	8,910			(7,174		)	(39,525		)
Total	$	(10,759	)	$	(71,190	)	$	(281,752	)
Closed gains (losses) on derivative instruments
Oil	$	(11,364	)	$	(17,701	)	$	346,404
Natural gas liquids	(7,780		)	—			—
Natural gas	3,510			414			50,641
Total	$	(15,634	)	$	(17,287	)	$	397,045
Total revenues	$	961,045		$	532,889		$	878,554
Production volumes
Oil (MBbl)	16,951			13,213			14,023
Natural gas liquids (MMgal)	220.7			163.5			170.7
Natural gas (MMcf)	33,528			27,204			35,604
Total production volumes (MBOE)	27,794			21,639			24,022
Average daily production volumes
Oil (MBbl/d)	46.4			36.1			38.4
Natural gas liquids (MMgal/d)	0.6			0.4			0.5
Natural gas (MMcf/d)	91.9			74.3			97.5
Total average daily production volumes (MBOE/d)	76.1			59.1			65.8
Permian Basin - Spraberry (Trend Area) Field production volumes (included in production volumes above)*
Oil (MBbl)	9,037			7,205			6,714
Natural gas liquids (MMgal)	127.4			105.3			86.7
Natural gas (MMcf)	17,717			16,163			13,338
Total production volumes (MBOE)	15,023			12,406			11,002
Permian Basin - Phantom Field production volumes (included in production volumes above)**
Oil (MBbl)	3,334			744			1,064
Natural gas liquids (MMgal)	64.9			12.5			15.1
Natural gas (MMcf)	11,337			2,548			2,155
Total production volumes (MBOE)	6,769			1,466			1,783
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	47.38		$	38.09		$	69.75



Natural gas liquids (per gallon)	$	0.41	$	0.30	$	0.29
Natural gas (per Mcf)	$	2.33	$	1.92	$	3.75
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	48.05	$	39.43	$	45.04
Natural gas liquids (per gallon)	$	0.45	$	0.30	$	0.29
Natural gas (per Mcf)	$	2.23	$	1.90	$	2.32
Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	6.61	$	7.94	$	9.51
Production and ad valorem taxes	$	2.14	$	1.98	$	2.39
Depreciation, depletion and amortization	$	17.39	$	20.70	$	24.72
Exploration expense	$	0.36	$	0.25	$	0.62
General and administrative	$	3.05	$	4.42	$	6.21

*The Spraberry (Trend Area) Field in the Permian Basin contained 15 percent or more of Energen’s total proved reserves as of December 31, 2017, 2016 and 2015.

**The Phantom Field in the Permian Basin contained 15 percent or more of Energen’s total proved reserves as of December 31, 2017.

Revenues: Our revenues fluctuate primarily as a result of realized commodity prices, production volumes and the value of our derivative contracts. Our revenues are predominantly derived from the sale of oil, natural gas liquids and natural gas.

For the year ended December 31, 2017, oil, natural gas liquids and natural gas sales rose $366.1 million or 58.9 percent from the same period of 2016. Particular factors impacting commodity sales for 2017 include the following:

•

Total production increased 28.4 percent to 27.8 MMBOE during 2017. Increased production related to new well performance from the Delaware Basin and Midland Basin horizontal well programs was partially offset by reduced production associated with a series of asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico and normal declines in the Delaware Basin 3rd Bone Spring, the Central Basin Platform and the vertical Wolfberry in the Midland Basin.


•	Oil volumes rose 28.3 percent to 16,951 MBbl during 2017.


•	Average realized oil prices in 2017 increased 21.9 percent to $48.05 per barrel.


•	Production of natural gas liquids rose 35 percent to 220.7 MMgal in 2017.


•	Average realized natural gas liquids prices rose 50 percent to an average price of $0.45 per gallon during 2017.


•	Natural gas production increased 23.2 percent to 33.5 Bcf in 2017.


•	Average realized natural gas prices in 2017 increased 17.4 percent to $2.23 per Mcf.

For the year ended December 31, 2016, oil, natural gas liquids and natural gas sales decreased $141.9 million or 18.6 percent from the same period of 2015. Particular factors impacting commodity sales for 2016 include the following:


•	Total production decreased 9.9 percent to 21.6 MMBOE during 2016.

•

Oil volumes fell 5.8 percent to 13,213 MBbl during 2016 as production declines in the Midland Basin Wolfberry, 3rd Bone Spring in the Delaware Basin and the Central Basin Platform along with production declines associated with a series of asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico that were partially offset by new well performance, net of production declines, in the horizontal Wolfcamp in the Midland and Delaware basins and also Spraberry in the Midland Basin.


•	Average realized oil prices in 2016 fell 12.5 percent to $39.43 per barrel.

•

Production of natural gas liquids decreased 4.2 percent to 163.5 MMgal in 2016. Production declines in the Midland Basin Wolfberry and 3rd Bone Spring in the Delaware Basin and declines from the asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico were partially offset by new well performance, net of production declines, in the horizontal Wolfcamp in the Midland and Delaware basins along with Spraberry in the Midland Basin.


•	Average realized natural gas liquids prices rose 3.4 percent to an average price of $0.30 per gallon during 2016.


•	Natural gas production decreased 23.6 percent to 27.2 Bcf in 2016 primarily due to the sale of natural gas assets in the San Juan Basin and production declines in the 3rd Bone Spring in the Delaware Basin and in the Midland Basin Wolfberry

partially offset by new horizontal Wolfcamp production in the Midland and Delaware basins and also Spraberry in the Midland Basin.


•	Average realized natural gas prices in 2016 fell 18.1 percent to $1.90 per Mcf.

Realized prices exclude the effects of derivative instruments.

Oil, natural gas liquids and natural gas production expense: The following table provides the components of our oil, natural gas liquids and natural gas production expenses:



Years ended December 31, (in thousands, except per unit data)	2017		2016		2015
Lease operating expenses	$	125,618	$	114,386	$	140,010
Workover and repair costs	48,872		46,619		68,428
Marketing and transportation	9,207		10,709		19,942
Total oil, natural gas liquids and natural gas production expense	$	183,697	$	171,714	$	228,380
Oil, natural gas liquids and natural gas production expense per BOE	$	6.61	$	7.94	$	9.51

Lease operating expense generally reflects year-over-year increases in the number of active wells resulting from Energen’s ongoing development and exploratory activities and also may be positively or negatively impacted by property acquisitions and dispositions.

•

In 2017, lease operating expense increased $11.2 million largely due to increased water disposal costs (approximately $8.9 million), higher gathering costs (approximately $2.7 million), additional equipment rental costs (approximately $1.5 million) and increased electrical costs (approximately $0.9 million) partially offset by decreased producing overhead costs (approximately $2.3 million) and decreased chemical and treatment costs (approximately $1.2 million).

•

In 2016, lease operating expense decreased $25.6 million largely due to decreased water disposal costs (approximately $8.9 million), lower non-operated costs (approximately $4.3 million), decreased gathering costs (approximately $3.7 million), lower labor costs (approximately $3.7 million), lower other operations and maintenance expense (approximately $3.5 million), decreased environmental compliance costs (approximately $1.2 million) and decreased electrical costs (approximately $0.5 million) partially offset by additional equipment rental costs (approximately $0.8 million) and increased chemical and treatment costs (approximately $0.7 million).

Workover and repair costs increased approximately $2.3 million in 2017 and decreased $21.8 million in 2016. In 2017, workover and repair costs remained relatively stable. Workover and repair costs in 2016 were lower largely due to lower incidence of well failures and reduced costs of services and materials.

In the years ended December 31, 2017 and 2016, marketing and transportation costs decreased $1.5 million and $9.2 million, respectively. The decline in 2017 was largely due to lower natural gas volumes as a result of the sale of certain San Juan Basin natural gas assets partially offset by higher volumes associated with the Delaware Basin. The decline in 2016 was largely due to lower natural gas volumes as a result of the sale of natural gas assets.

Production and ad valorem taxes: The following table provides details of our production and ad valorem taxes:



Years ended December 31, (in thousands, except per unit data)	2017		2016		2015
Production taxes	$	47,888	$	31,849	$	38,197
Ad valorem taxes	11,559		11,089		19,183
Total production and ad valorem tax expense	$	59,447	$	42,938	$	57,380
Total production and ad valorem tax expense per BOE	$	2.14	$	1.98	$	2.39

Production and ad valorem taxes were $59.4 million , $42.9 million and $57.4 million during the years ended December 31, 2017, 2016 and 2015, respectively. In 2017, production-related taxes were $16 million higher with approximately $7 million attributed to increased commodity market prices and approximately $9.1 million attributed to higher production volumes. In 2016, production-related taxes were $6.3 million lower with approximately $2.6 million attributed to decreased commodity market prices and approximately $3.8 million attributed to lower production volumes. Commodity market prices exclude the effects of derivative

instruments for purposes of determining production taxes. In 2017, ad valorem taxes increased $0.5 million. Decreased ad valorem taxes of $8.1 million in 2016 were primarily driven by the factor adjusted price impact on our Texas oil and natural gas properties.

Depreciation, depletion and amortization: Energen had DD&A expense of $483.4 million , $448.0 million and $593.8 million during the years ended December 31, 2017, 2016 and 2015, respectively. DD&A expense rose $35.4 million in 2017 and decreased $145.8 million in 2016. The average DD&A rates were $17.39 per BOE in 2017, $20.70 per BOE in 2016 and $24.72 per BOE in 2015. In 2017, higher production volumes increased DD&A expense approximately $126 million partially offset by lower per unit DD&A rates of approximately $90.2 million. The decrease in the 2016 per unit DD&A rate, which contributed approximately $86.6 million to the decrease in DD&A expense, was largely due to lower rates resulting from asset impairments. Decreased production volumes reduced DD&A expense approximately $58.3 million in 2016.

Asset impairment: Non-cash impairment writedowns are reflected in asset impairment in the consolidated statements of operations.

Permian Basin: During 2017, Energen recognized non-cash impairment writedowns in the Permian Basin of $1.1 million to adjust the carrying amount of these proved properties to their fair value.

During the first quarter of 2016, Energen recognized non-cash impairment writedowns in the Permian Basin of $208.3 million to adjust the carrying amount of these properties to their fair value. We estimate future discounted cash flows in determining fair value using commodity assumptions, which are based on the commodity price curve for five years and then escalated at 3 percent through our assumed price cap. Our commodity price assumptions declined in the first quarter of 2016 by approximately 5 percent for oil and 4 percent for natural gas in comparable periods.

For 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $1,092.2 million to adjust the carrying amount of these properties to their fair value primarily due to commodity price declines. We estimate future discounted cash flows in determining fair value using commodity assumptions, which are based on the commodity price curve for five years and then escalated at 3 percent through our assumed price cap.

In 2017, Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties of $0.6 million . During 2016, Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties in the Delaware Basin and the Central Basin Platform of $4.8 million . Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties in the Delaware Basin of $29.2 million in 2015.

San Juan Basin: During the first quarter of 2016, Energen recognized non-cash impairment writedowns on held for sale properties in the San Juan Basin of $7.5 million to adjust the carrying amount of these properties to their fair value.

Energen recognized non-cash impairment writedowns on properties in the San Juan Basin of $133.1 million during the fourth quarter of 2015 to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. These remaining properties were designated as held for sale as of December 31, 2015. During 2015, Energen recognized unproved leasehold writedowns on San Juan Basin properties of $37.9 million .

Exploration: The following table provides details of our exploration expense:



Years ended December 31, (in thousands, except per unit data)	2017		2016		2015
Geological and geophysical	$	7,372	$	5,032	$	7,316
Dry hole costs	2,130		16		7,097
Delay rentals and other	573		367		465
Total exploration expense	$	10,075	$	5,415	$	14,878
Total exploration expense per BOE	$	0.36	$	0.25	$	0.62

Exploration expense increased $4.7 million in 2017 primarily due to higher seismic and dry hole costs. Exploration expense decreased $9.5 million during 2016 primarily due to lower dry hole costs and seismic costs.

General and administrative: The following table provides details of our G&A expense:



Years ended December 31, (in thousands, except per unit data)	2017		2016		2015
General and administrative	$	19,399	$	15,150	$	30,578
Benefit and performance-based compensation costs	29,411		35,218		64,805
Labor costs	36,013		45,321		53,749
Total general and administrative expense	$	84,823	$	95,689	$	149,132
Total general and administrative expense per BOE	$	3.05	$	4.42	$	6.21

Total G&A expense declined $10.9 million in 2017 primarily due to lower labor costs (approximately $9.3 million) and decreased costs related to Energen’s benefit and performance-based compensation plans (approximately $5.8 million) partially offset by increased professional services (approximately $3.0 million). In 2016, total G&A expense decreased $53.4 million largely due to decreased costs from Energen’s benefit and performance-based compensation plans (approximately $29.6 million), lower labor costs (approximately $13.4 million), decreased legal expenses (approximately $5.4 million), decreased professional services (approximately $5.3 million), decreased recruiting expenses (approximately $1.2 million), lower insurance costs (approximately $1.1 million) and decreased vehicle expenses (approximately $1 million) partially offset by charges associated with the workforce reduction of $5.0 million. Included in costs from the benefit and performance-based compensation plans were pension costs of $3.3 million (all of which was settlement expense) and $31.3 million (including settlement expense of $29.8 million ) for the years ended December 31, 2016 and 2015, respectively.

Gain on sale of assets and other, net: Energen had gains on the sale of assets and other of $13.0 million , $246.9 million and $26.6 million for the years ended December 31, 2017, 2016 and 2015, respectively. Gains on the sale of assets and other in the current year include a $4.4 million gain from the August 2017 sale of certain unproved leasehold properties in Wyoming and a$6.4 million gain from the December 2017 lawsuit settlement over certain leasehold interests.

During 2016, Energen completed a series of asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico for an aggregate purchase price of $552 million . These transactions had closing dates of June 3, June 7, June 30, July 15 and August 9 of 2016 with various effective dates ranging from March 1, 2016 to June 30, 2016. Minor portions of the assets were transferred to other parties upon the exercise of preferential purchase rights under pre-existing joint operating agreements in the ordinary course of business. Pre-tax proceeds to Energen were approximately $532.2 million after purchase price adjustments of approximately $19 million related to the operations of the properties subsequent to the effective dates and other one-time adjustments including transfer payments and certain amounts due to the buyer, but before consideration of transaction costs of approximately $5 million . In the years ended December 31, 2017 and 2016, Energen recognized pre-tax post-closing adjustment losses of $0.6 million and pre-tax gains of $246.3 million on the sales, respectively. Energen used the proceeds from the sale to fund ongoing operations.

On March 31, 2015, Energen completed the sale of the majority of our natural gas assets in the San Juan Basin in New Mexico and Colorado (effective as of January 1, 2015) for an aggregate purchase price of $395 million . The sales proceeds were reduced by purchase price adjustments of approximately $11 million related to the operations of the San Juan Basin properties subsequent to December 31, 2014 and one-time adjustments related primarily to liabilities assumed by the buyer, which resulted in pre-tax proceeds to Energen of approximately $384 million before consideration of transaction costs of approximately $2.8 million . Energen recognized a pre-tax gain of $27.0 million on the sale. Energen used the proceeds from the sale to reduce long-term indebtedness. At December 31, 2014, proved reserves associated with these San Juan Basin held for sale properties totaled 69,038 MBOE.

Interest expense: Interest expense rose $1.5 million during 2017 primarily due to increased borrowings under our credit facility partially offset by reduced interest costs related to the January 2017 redemption of the $2.0 million of 7.40% Medium-term Notes, Series A, due July 24, 2017 and $5.0 million of 7.60% Medium-term Notes, Series A, due July 26, 2027 along with the scheduled reduction of $17.0 million of long-term debt in July 2017. Interest expense decreased $6 million during 2016 primarily due to decreased borrowings under our credit facility resulting from proceeds on asset sales and our first quarter 2016 equity offering. The average daily outstanding balance under credit facilities was $131.8 million in 2017. The average daily outstanding balance under credit facilities was $33.6 million in 2016 as compared to $358.9 million in 2015.

Income tax expense (benefit): Income tax expense decreased $119.8 million in 2017 largely due to the impact of the Tax Cuts and Jobs Act partially offset by higher pre-tax income. The Tax Cuts and Jobs Act was signed into law on December 22, 2017. The changes in tax rates and tax law are accounted for in the period of enactment. Accordingly, Energen recognized the impact

as a discrete event in the fourth quarter of 2017 and remeasured its deferred tax assets and liabilities through income tax expense. Energen recorded a net provisional income tax benefit of $240 million for the impact of the Tax Cuts and Jobs Act, primarily from the corporate rate reduction. Income tax expense increased $455.4 million in 2016 primarily due to higher pretax income. In addition, the Company recorded $2 million and $2.5 million of tax expense for the change in the valuation allowance for our deferred tax assets as of December 31, 2017, and 2016, respectively, due to the uncertainty of their realization.

FINANCIAL POSITION AND LIQUIDITY

Cash Flow

The key drivers impacting our cash flow from operations are our oil, natural gas liquids and natural gas production volumes and realized commodity market prices, net of the effects of settlements on our derivative commodity instruments. We rely on our cash flows from operations to fund our capital spending plans and working capital requirements. Cash flows may be supplemented, as needed, by borrowings under our syndicated credit facility.

Net cash provided by operating activities: Energen’s net cash from operating activities totaled $569.4 million , $295.1 million and $719.3 million in 2017, 2016 and 2015, respectively. During 2017, net income was impacted by the increased price environment along with higher production volumes (including the impact of prior year asset sales). Net income was also impacted by certain non-cash charges including deferred income taxes, which were impacted by the Tax Cuts and Jobs Act, and the change in derivative fair values. Net income in 2016 was impacted overall by the decreased price environment and lower production volumes (including the impact of asset sales). Also affecting net income were certain non-cash charges including DD&A, asset impairment charges, deferred income taxes and the change in derivative fair value. The gain on sale of assets totaled $246.3 million in 2016. During 2015, net income was impacted by non-cash charges, including asset impairment charges, deferred income taxes and the change in derivative fair value. During 2015, operating cash flows were impacted by declining commodity prices. The Company’s working capital needs were also influenced by accrued taxes and the timing of payments and recoveries for all years and included pension contributions during 2016 and 2015.

Net cash used in investing activities: Energen made net investments of $1,183.0 million during 2017. Energen invested $276.8 million on a cash basis in property acquisitions including approximately $273 million of unproved leaseholds; $233.2 million for development costs including approximately $71 million to drill 19.6 net development and service wells; $668.4 million for exploration including approximately $411 million to drill 72.8 net exploratory wells. Included in the proceeds from asset sales in 2017 are cash proceeds of $4.4 million from the sale of certain unproved leasehold properties in Wyoming. Energen made net investments of $66.1 million during 2016. Energen invested $147.9 million on a cash basis in property acquisitions including approximately $143.8 million of unproved leaseholds; $89.1 million for development costs including approximately $42 million to drill 21 net development and service wells; $344.1 million for exploration including approximately $175 million to drill 53 net exploratory wells. Included in the proceeds from assets sales in 2016 are cash proceeds of $528.1 million from the series of asset sales of certain non-core Permian Basin assets in the Delaware Basin and in the San Juan Basin. During 2015, the Company made net investments of $847.3 million . Energen invested $87.4 million in property acquisitions including approximately $85.5 million of unproved leaseholds; $386.4 million for development costs (includes the reversal of approximately $17.2 million of accrued development cost) including approximately $139 million to drill 63 net development and service wells; and $753.1 million for exploration (includes the reversal of approximately $111.1 million of accrued exploration cost) including approximately $492 million to drill 100 net exploratory wells. Included in the proceeds from asset sales and the sale of Alabama Gas Corporation in 2015 are cash proceeds of $384 million from the sale of certain San Juan Basin assets and $8.6 million from the sale of Alagasco.

During 2016, Energen added 115.5 MMBOE of proved reserves from discoveries and other additions, primarily the result of exploratory and development drilling that increased the number of proved undeveloped locations in the Permian Basin. Energen added approximately 64 MMBOE and 133 MMBOE of proved reserves in 2016 and 2015, respectively.

Net cash provided by financing activities: The Company provided $228.0 million from net financing activities in 2017 primarily due to an increase in credit facility borrowings partially offset by the redemption of $2 million of 7.40% Medium-term Notes, Series A, due July 24, 2017 and $5 million of 7.60% Medium-term Notes, Series A, due July 26, 2027 along with $17 million of scheduled reductions in long-term debt in July 2017. The Company provided $155.9 million from net financing activities in 2016 primarily due to the issuance of 18,170,000 shares of common stock largely offset by the repayment of credit facility borrowings. In 2015, the Company provided $127.4 million from net financing activities primarily due to the issuance of 5,700,000 shares of common stock largely offset by the repayment of credit facility borrowings. For each of the years, net cash provided by financing activities reflected cash received from the issuance of common stock through the Company’s stock-based compensation plan and cash paid taxes on shares withheld. During 2015, net cash provided by financing activities also reflected dividends paid to common shareholders.

Capital Expenditures

Capital spending at Energen is detailed below.



Years ended December 31, (in thousands)	2017		2016		2015
Property acquisitions	$	283,215	$	147,733	$	87,556
Development	233,247		89,101		370,331
Exploration	668,411		344,061		641,983
Other	4,469		2,003		14,938
Total	1,189,342		582,898		1,114,808
Less exploration expenditures charged to income	2,705		4,818		74,198
Net capital expenditures	$	1,186,637	$	578,080	$	1,040,610

During 2017, 2016 and 2015, Energen completed a total of $273.3 million , $143.7 million and $85.7 million , respectively, in various purchases, leases and renewals of unproved leasehold largely in the Permian Basin.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

Outlook

Realized commodity prices and production levels by commodity type are the two primary drivers of our liquidity. Historically, prices received for oil, natural gas liquids and natural gas production have been volatile because of supply and demand factors, general economic conditions and seasonal weather patterns. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of the Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas.

We engage in derivative risk management activities in order to reduce the risk associated with commodity price fluctuations. Commodity hedges in place for 2018 and 2019 will help mitigate some of the commodity price volatility. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for a full detail of our hedged volumes.

Production from the liquids rich Permian Basin in 2018 is estimated to range from 33.4 MMBOE to 36 MMBOE, with a midpoint of 34.7 MMBOE, including approximately 27.8 MMBOE of estimated production from proved reserves owned at December 31, 2017. Production estimates do not include amounts related to potential future acquisitions. In the event Energen is unable to fully invest in its capital investment opportunities, future operating revenues, production and proved reserves could be negatively affected.

Production volumes by commodity in 2018 are expected to be as follows:



Year ended December 31, 2018	MMBOE	MBOE/d
Oil	20.8	57
Natural gas liquids	6.6	18
Natural gas	7.3	20
Total (midpoint of range)	34.7	95

Total production from proved properties is expected to increase approximately 0.1 percent and total production from all properties owned at December 31, 2017 is expected to increase approximately 24.9 percent. Energen expects a compound annual decline rate for proved developed producing properties owned at December 31, 2017 for the 5 year period 2017 to 2022, for the 10 year period 2017 to 2027 and for the 20 year period 2017 to 2037 of approximately 15.5 percent, 11.9 percent and 9.3 percent, respectively. Various factors influence decline rates. For example, certain properties may have production curves that decline at faster rates in the early years of production and at slower rates in later years. Accordingly, the decline rate for a single year is influenced by numerous factors, including but not limited to, the mix of types of wells, the mix of newer versus older wells, and the effect of enhanced recovery activities, but it is not necessarily indicative of future decline rates. The above proved developed producing properties decline rate is not necessarily indicative of terminal decline rates on a long-term basis.

Revenues and related accounts receivable from oil and natural gas operations are generated primarily from the sale of produced oil, natural gas liquids and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect Energen’s overall exposure to credit risk, either positively or negatively, in that our oil and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

Energen plans to continue investing capital in oil and natural gas production operations. For 2018, we expect our oil and natural gas capital spending to range from $1.1 billion to $1.3 billion, including approximately $238 million for the development of previously identified proved undeveloped reserves. Future success in maintaining and growing reserves and production is highly dependent on the results of our drilling program and our ability to add reserves economically during a volatile market for crude oil and natural gas.

Capital expenditures in the Permian Basin by area during 2018 are planned as follows:



Year ended December 31, (in millions)	2018
Midland Basin	$ 550-650
Delaware Basin	550-650
Total	$ 1,100-1,300

Energen anticipates drilling and/or completing the following operated net horizontal wells by area during 2018.



	Midland Basin	Delaware Basin	Total
Drilled but uncompleted wells as of December 31, 2017 (to be completed in 2018)	16	12	28
Wells drilled and completed during 2018	46	39	85
Drilled but uncompleted wells as of December 31, 2018	19	16	35

In addition, Energen plans to drill 7 vertical wells in the Midland Basin and complete 6 of them during 2018. Energen expects to run an average of 9 operated drilling rigs during 2018 to drill these wells.

Energen also may allocate additional capital for other oil and natural gas activities such as property acquisitions and additional development of existing properties. Energen may evaluate acquisition opportunities which arise in the marketplace. Energen’s ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions, except as discussed above, are not included in the aforementioned estimate of oil and natural gas investments and could result in capital expenditures different from those outlined above.

Credit Facility and Working Capital

At December 31, 2017, we had $795 million of committed financing available under our credit facility. On September 2, 2014, Energen entered into a five -year syndicated secured credit facility with domestic and foreign lenders. On October 25, 2016, the borrowing base and aggregate commitments were reaffirmed at $1.05 billion each with no changes in association with the semi-annual redetermination required under the agreement. On April 21, 2017, the borrowing base was increased to $1.4 billion . The aggregate commitments under the credit facility did not change and remained at $1.05 billion . On November 9, 2017, the borrowing base was increased to $1.7 billion . The aggregate commitments under the credit facility did not change and remained at $1.05 billion . Energen’s obligations under the syndicated credit facility are unconditionally guaranteed by Energen Resources. To finance our operations, working capital and capital spending, we expect to use internally generated cash flow from operations supplemented, if necessary, by our existing five-year syndicated credit facility.

Access to capital is an integral part of Energen’s business plan. Energen may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. As of December 31, 2017, the Company had $255 million outstanding under its revolving credit facility. While we expect to have ongoing access to our credit facility and capital markets, continued access could be adversely affected by current and future economic and business conditions.

Our debt facilities are subject to certain financial and non-financial covenants as discussed in Note 3, Long Term Debt, in the Notes to Financial Statements. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other noncash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0; and to maintain a ratio of consolidated current assets (adjusted to include amounts available for borrowings and exclude non-cash derivative instruments) to consolidated current liabilities (adjusted to exclude maturities under the credit facility and non-cash derivative instruments) greater than or equal to 1.0 to 1.0. We are also bound by covenants which limit our ability to incur additional indebtedness, make certain distributions or alter our corporate structure. Energen may not pay dividends if an event of default exists, if the payment would result in an event of default or if availability is less than 10 percent of the loan limit under the credit facility. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. In addition, the terms of our credit facility limit the amount we can borrow to a borrowing base amount which is determined by our lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria including commodity price outlook. The borrowing base amount is subject to redetermination semi-annually and for event-driven unscheduled redeterminations. Our next scheduled redetermination is April 1, 2018.

Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen or Energen Resources will constitute an event of default by Energen. The Indenture does not include a restriction on the payment of dividends.

As of December 31, 2017, we were in compliance with our covenants and expect to maintain compliance during 2018. However, in future periods, factors including those outside of our control may prevent us from maintaining compliance with the financial and non-financial covenants, including our total debt to EBITDAX covenant. Such factors may include commodity price declines, lack of liquidity in property and capital markets and our continuing ability to execute on our business plan. The borrowing base on our credit facility is scheduled to be redetermined in April and October of 2018. In the event that we are unable to remain in compliance with our financial and non-financial covenants, we would seek covenant relief at a scheduled redetermination date or at an interim date, as appropriate. However, no assurances can be given with respect to such relief. If any such covenant violations are not waived by the lenders such violation would result in an event of default that could trigger acceleration of payment of the amounts outstanding under our credit facility and long term note agreements. Additionally, the lenders could refuse to make additional loans under the credit facility, take possession of any collateral, and exercise other remedies or rights that may be available to them, all of which could have a material adverse effect on the business and financial condition of the Company.

Under Energen’s credit facility, a cross default provision provides that any debt default of more than $75 million by Energen or Energen Resources will constitute an event of default by Energen.

At December 31, 2017, Energen reported negative working capital of $130.8 million arising from current liabilities of $322.2 million exceeding current assets of $191.4 million . Working capital at Energen was influenced by accounts payable and accrued capital costs. Energen has $71.4 million in current liabilities associated with its derivative financial instruments at December 31, 2017. Energen relies upon cash flows from operations supplemented by our credit facility to fund working capital needs.

Income Taxes

On December 22, 2017, the President signed into law the Tax Cuts and Jobs Act. This act significantly changed U.S. tax laws by, among other things, reducing the federal corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax (AMT) for tax years beginning after December 31, 2017, and allowing full expensing for certain business assets acquired and placed in service after September 27, 2017, through 2022. These tax reform provisions, along with the ability to continue expensing intangible drilling costs in the year incurred, would favorably impact Energen’s future cash flows.

Energen recorded a net provisional income tax benefit of $240 million for the impact of the Tax Cuts and Jobs Act, primarily due to the corporate rate reduction and the remeasurement of Energen’s net deferred tax liability. Due to the repeal of the corporate AMT, existing AMT credits may be utilized to offset the regular income tax liability of a corporation effective for tax years beginning in 2018. In addition, AMT credits are refundable to the extent the AMT credits exceed regular tax liabilities in tax years 2018 through 2021 (fully allowed or refunded before 2022). Based on current projections which indicates that the credits will most likely not offset regular tax liabilities, Energen anticipates receiving cash refunds of its $70.7 million net minimum tax credit over the taxable periods 2018-2021 due to this change. The amount of the anticipated cash refund incorporates an estimate of the potential reduction in the refund due to the effect of sequestration, which is currently expected to apply in each of the years between 2018 and 2021.

While there are certain provisions of the Tax Cuts and Jobs Act, such as expanded limitations on executive compensation under IRC Section 162(m) and limitations on business interest deductions, especially in periods after 2021, which may unfavorably

impact Energen’s future income tax provisions, the Company does not anticipate these tax law changes would have a material impact to its near-term cash flows.

Workforce Reduction

On January 22, 2016 and March 18, 2016, we reduced our workforce as part of an overall plan to reduce costs and better align our workforce with the needs of our business. In connection with the reductions, we incurred charges of approximately $5.0 million during 2016 for one-time termination benefits which are included in general and administrative expense on the consolidated statements of operations.

Equity Offering and Shares Issued

During the first quarter of 2016, Energen issued 18,170,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $381.1 million, after deducting offering expenses. During the second quarter of 2015, Energen issued 5,700,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $398.6 million, after deducting offering expenses. Net proceeds from these offerings were used to repay borrowings under our credit facility and for general corporate purposes.



(in thousands)	December 31, 2017	December 31, 2016
Shares outstanding	97,203	97,075
Treasury stock*	3,124	3,064
Shares issued	100,327	100,139

*Excludes 67,620 shares and 61,845 shares held in the 1997 Deferred Compensation Plan at December 31, 2017 and 2016, respectively.

Dividends

Employee Benefit Plans

Energen terminated its qualified defined benefit pension plan on January 31, 2015 and distributed benefits in December 2015. In February 2018, Energen received notice that the Pension Benefit Guaranty Corporation had completed its audit of the termination of the pension plan and of the distribution of plan assets noting no exceptions.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans were made in the first quarters of 2016 and 2015.

Stock Repurchase Authorization

The Company may periodically repurchase shares of its common stock through open market or negotiated purchases. Such repurchases would be pursuant to a 3,600,000 share repurchase authorization approved by the Board of Directors on October 22, 2014. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2017, 2016 and 2015. As of December 31, 2017 , a total of 3,373,161 shares remain authorized for future repurchase. The timing and amounts of any repurchases are subject to changes in market conditions and other business considerations. Energen also acquires shares in connection with withholdings from participants to satisfy tax obligations under Energen’s stock compensation plans. For the years ended December 31, 2017 , 2016 and 2015 , Energen acquired 60,762 shares, 88,320 shares and 73,126 shares, respectively, in connection with its stock compensation plans.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes Energen’s significant contractual cash obligations, other than hedging contracts, as of December 31, 2017 :



			Payments Due Before December 31,
(in thousands)	Total		2018		2019-2020		2021-2022		2023 and Thereafter
Long-term debt ⁽¹⁾	$	785,000	$	—	$	255,000	$	420,000	$	110,000
Interest payments on debt	172,595		34,879		67,406		30,428		39,882
Operating leases	7,891		4,648		3,243		—		—
Asset retirement obligations ⁽²⁾	515,783		16		—		—		515,767
Total contractual cash obligations	$	1,481,269	$	39,543	$	325,649	$	450,428	$	665,649

(1) Long-term debt obligations include approximately $0.4 million of unamortized debt discounts as of December 31, 2017 .

(2) Represents the estimated future asset retirement obligation on an undiscounted basis.

Under various agreements for third-party gathering, treatment, transportation or other services, Energen is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 2.9 MMBOE through October 2020 .

The contractual obligations reported above exclude Energen’s liability of $8.4 million related to Energen’s provision for uncertain tax positions. Energen cannot make a reasonably reliable estimate of the amount and period of related future payments for such liability.

In 2011, Energen Resources received an Order to Perform Restructured Accounting and Pay Additional Royalties (the Order), following an audit performed by the Taxation and Revenue Department (the Department) of the State of New Mexico on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Order addressed ONRR’s efforts to change accounting and reporting practices, and to unbundle fees charged by third parties that gather, compress and transport natural gas production. ONRR now maintains that all or some of such fees are not deductible.

Energen Resources appealed the Order in 2011, and in July 2012, on a motion from ONRR, the Order was remanded. In August 2014, ONRR issued its Revised Order and Energen Resources appealed the Revised Order. In the Revised Order, ONRR ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700 . At ONRR’s request; the Revised Order was also remanded in August 2015. On April 15, 2016 ONRR issued its Second Revised Order. The Second Revised Order directs Energen Resources to pay additional royalties of $189,000 , replacing the previous demand of $129,700 . Energen estimates that application of the ONRR position to all of the Company’s federal leases would result in ONRR claims up to approximately $24 million , plus interest and penalties from 2004 forward. ONRR began implementing its unbundling initiative in 2010, but seeks to implement its revisions retroactively, despite the fact that they conflict with previous audits, allowances and industry practice. Energen is contesting the Second Revised Order, the predecessor orders and the findings. Management is unable, at this time, to determine a range of reasonably possible losses, and no amount has been accrued as of December 31, 2017 .

Derivative Commodity Instruments

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net loss position with all fourteen of our active counterparties at December 31, 2017 . Energen has policies in place to limit hedging to not more than 80 percent of our estimated annual production; however, Energen’s credit facility contains a covenant which operates to limit hedging at a lower threshold in certain circumstances.

Energen has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas liquids and natural gas may have on the fair value of its derivative instruments. This analysis measured the impact on the commodity derivative instruments and, thereby, did not consider the underlying exposure related to the commodity. At December 31, 2017 , Energen was in a net loss position of $80.3 million for derivative contracts and estimates that a 10 percent increase in the commodities prices would have resulted in an approximate $79.9 million change in the fair value of open derivative contracts and that a 10 percent decrease in the commodities prices would have resulted in an approximate $58.7 million change in the fair value of open derivative contracts; however, gains and losses on derivative contracts are expected to be similarly offset by sales at the spot market price. The hypothetical change in fair value was calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes and did not include the impact of related taxes on actual cash prices.

All derivatives are recognized at fair value under the fair value hierarchy as discussed in Note 2, Summary of Significant Accounting Policies, in the Notes to Financial Statements. Level 3 liabilities as of December 31, 2017 represent an immaterial amount of total assets and approximately 2 percent of total liabilities. Changes in fair value primarily result from price changes in the underlying commodity. Energen has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its Level 3 instruments. We estimate that a 10 percent increase or decrease in commodity prices would result in an approximate $9.2 million change in the fair value of open Level 3 derivative contracts and to the results of operations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Energen’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Management has identified the following critical accounting policies in the application of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by Energen. The application of these accounting policies necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events that could have a material impact on the financial statements.

Accounting for Oil and Natural Gas Producing Activities and Related Proved Reserves: Energen utilizes the successful efforts method of accounting for its oil and natural gas producing activities. Acquisition and development costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The technologies associated with these proved reserve estimates are analysis of well production data, geophysical data, wireline and core data. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas proved reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and natural gas proved reserves have been determined by Company engineers. Independent oil and natural gas reservoir engineers have audited the estimates of proved reserves of crude oil, natural gas liquids and natural gas attributed to Energen’s net interests in oil and natural gas properties as of December 31, 2017 . The independent reservoir engineers have issued reports covering approximately 99 percent of the Company’s ending proved reserves and in their judgment these estimates were reasonable in the aggregate. Energen’s production of proved undeveloped reserves requires the drilling of development wells and the installation or completion of related infrastructure facilities.

Changes in oil and natural gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated proved reserves held by Energen. If proved reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if proved reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property’s book value if an impairment is warranted.

The table below reflects an estimated increase in 2018 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and natural gas reserve amounts at December 31, 2017 :

Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

Asset Impairments: Oil and natural gas proved properties periodically are assessed for possible impairment on a field-by-field basis using the estimated undiscounted future cash flows. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. We monitor the business environment and our oil and natural gas properties for events that could result in a potential impairment. Further, we make assumptions about future expectations in our evaluation of potential impairment. Such assumptions include, but are not necessarily limited to, commodity prices and related basis differentials, transportation costs, inflation assumptions, well and reservoir performance, severance and ad valorem taxes, other operating and future development costs, and general business plans. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimates and can have a positive or negative impact on our need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact Energen’s original and ongoing assessments of potential impairment.

Our commodity price assumption is a significant and volatile uncertainty in our estimate, and we are unable to reliably forecast future commodity prices. Our assumption is therefore based on the commodity price curve for the next five years and then escalated at 3 percent through our assumed price caps. Our other assumptions generally have less volatility than the price assumption with variances tending to be field specific and more localized in effect. However, these assumptions can also be impacted by a higher or lower inflationary environment, limitations on takeaway capacity, well and reservoir performance over time, changes to governmental taxation, or changes to cost assumptions, operational and development plans, or the general economic or business environment.

If a material event occurs, we make an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, we will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows.

We may also recognize impairments of capitalized costs for unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes in economic factors and potential shifts in business strategy employed by management. We consider a combination of geologic and economic factors to evaluate the need for impairment of these costs.

Certain impairments were recognized during 2017 as discussed under Asset Impairment in our Results of Operations. We estimate a further decline in our price assumptions by 10 percent from December 31, 2017 prices (assuming all other assumptions are held constant) would result in no additional expense. Other assumptions such as operating costs, transportation costs, well and reservoir performance, severance tax rates and ad valorem taxes, operating and development plans may also change given an assumed 10 percent commodity price decline. However, we are unable to estimate their correlation to the price change and these other assumptions may worsen or partially mitigate some of the estimated impairment.

Derivatives: Energen periodically enters into derivative commodity instruments to manage its exposure to oil, natural gas liquids and natural gas price volatility. Derivative transactions are accounted for as mark-to-market transactions with gains and losses reported in gain (loss) on derivative instruments, net. Energen does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.

Asset Retirement Obligation: Energen records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, Energen will settle the obligation for its recorded amount and recognize the resulting gain or loss. Energen has an obligation to remove tangible equipment and restore land at the end of oil and natural gas production operations. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in contractual, regulatory, political, environmental, safety and public relations considerations.

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD

See Note 18, Recently Issued Accounting Standards, in the Notes to Financial Statements for information regarding recently issued accounting standards.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information below should be read in conjunction with the related disclosures in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Outlook” and in Note 7, Derivative Commodity Instruments, and in Note 8, Fair Value Measurements, in the Notes to Financial Statements.

We are exposed to various market risks including commodity price risk, counterparty credit risk and interest rate risk. We seek to manage these risks through our risk management program which often includes the use of derivative instruments. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Commodity price risk: Energen’s major market risk exposure is in the pricing applicable to its oil and natural gas production. Historically, prices received for oil, natural gas liquids and natural gas production have been volatile due to world and national supply-and-demand factors, seasonal weather patterns and general economic conditions. Crude oil prices also are affected by quality differentials, by worldwide political developments and by actions of the Organization of the Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply-and-demand factors, including seasonal factors and the availability and price of transportation to consuming areas. As impacted by such commodity price volatility during 2017, our average realized oil prices increased 21.9 percent to $48.05 per barrel, average realized natural gas liquids prices rose 50 percent to an average price of $0.45 per gallon and average realized natural gas prices increased 17.4 percent to $2.23 per Mcf.

As of December 31, 2017 (except as noted), Energen entered into the following transactions for 2018 and subsequent years:



Production Period	Description	Total Hedged Volumes		Average Contract Price	Fair Value (in thousands)
Oil
2018	NYMEX Three-Way Collars	13,500	MBbl		$	(40,002	)
	Ceiling sold price (call)			$60.04 Bbl
	Floor purchased price (put)			$45.47 Bbl
	Floor sold price (put)			$35.47 Bbl
2018	NYMEX Swaps	360	MBbl	$60.41 Bbl	*
2019	NYMEX Three-Way Collars	4,680	MBbl		(7,736		)
	Ceiling sold price (call)			$60.84 Bbl
	Floor purchased price (put)			$45.00 Bbl
	Floor sold price (put)			$35.00 Bbl
	NYMEX Three-Way Collars	720	MBbl		*
	Ceiling sold price (call)			$66.03 Bbl
	Floor purchased price (put)			$50.00 Bbl
	Floor sold price (put)			$40.00 Bbl
Oil Basis Differential
2018	WTI/WTI Basis Swaps	10,800	MBbl	$(1.01) Bbl	(11,374		)
2019	WTI/WTI Basis Swaps	4,680	MBbl	$(0.44) Bbl	(626		)
2019	WTI/WTI Basis Swaps	360	MBbl	$(0.40) Bbl	*
Natural Gas Liquids
2018	Liquids Swaps	105.8	MMGal	$0.59 Gal	(15,355		)
2019	Liquids Swaps	25.2	MMGal	$0.66 Gal	(524		)
Natural Gas
2018	Basin Specific Swaps - Permian	3.6	Bcf	$2.56 Mcf	1,736



Derivative contracts (closed but not cash settled)	(6,384		)
Total	$	(80,265	)
WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
*Contracts entered into subsequent to December 31, 2017

Realized prices are anticipated to be lower than New York Mercantile Exchange prices primarily due to basis differences and other factors.

Counterparty credit risk: Our principal exposure to credit risk is through the sale of our oil, natural gas liquids and natural gas production, which we market to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect our overall exposure to credit risk. We consider the credit quality of our purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

We are also at risk for economic loss based upon the credit worthiness of our derivative instrument counterparties. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by Energen. All hedge transactions are subject to Energen’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. Energen formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge.

Interest rate risk: Our interest rate exposure as of December 31, 2017 primarily relates to our credit facility with variable interest rates. As of December 31, 2017 , the Company had $255 million outstanding under its credit facility. The weighted average interest rate for amounts outstanding at December 31, 2017 was 2.77 percent . All long-term debt obligations, other than our credit facility, were at fixed rates at December 31, 2017.


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION

INDEX TO FINANCIAL STATEMENTS



		Page
1.	Financial Statements

	Report of Independent Registered Public Accounting Firm	47

	Consolidated Balance Sheets as of December 31, 2017 and 2016	48

	Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	50

	Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015	51

	Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2017, 2016 and 2015	52

	Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	53

	Notes to Financial Statements	54

Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energen Corporation:

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated financial statements, including the related notes of Energen Corporation and its subsidiaries listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017 based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated 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 consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 (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 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.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 28, 2018

We have served as the Company’s auditor since 1982.

ENERGEN CORPORATION

CONSOLIDATED BALANCE SHEETS



(in thousands)	December 31, 2017			December 31, 2016

ASSETS
Current Assets
Cash and cash equivalents	$	439		$	386,093
Accounts receivable, net	158,787			73,322
Inventories, net	13,177			14,222
Derivative instruments	—			50
Income tax receivable	6,905			27,153
Prepayments and other	12,085			5,071
Total current assets	191,393			505,911
Property, Plant and Equipment
Oil and natural gas properties, successful efforts method
Proved properties	8,466,708			7,543,464
Unproved properties	453,028			196,888
Less accumulated depreciation, depletion and amortization	(4,200,797		)	(3,723,669		)
Oil and natural gas properties, net	4,718,939			4,016,683
Other property and equipment, net	44,581			44,869
Total property, plant and equipment, net	4,763,520			4,061,552
Other postretirement assets	2,646			3,619
Noncurrent income tax receivable, net	70,716			—
Other assets	5,620			8,741
TOTAL ASSETS	$	5,033,895		$	4,579,823

The accompanying Notes to Financial Statements are an integral part of these statements.

ENERGEN CORPORATION

CONSOLIDATED BALANCE SHEETS



(in thousands, except share data)	December 31, 2017			December 31, 2016

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	—		$	24,000
Accounts payable	75,167			65,031
Accrued taxes	2,631			7,252
Accrued wages and benefits	26,170			25,089
Accrued capital costs	74,909			79,988
Revenue and royalty payable	54,072			51,217
Derivative instruments	71,379			65,467
Other	17,916			20,160
Total current liabilities	322,244			338,204
Long-term debt	782,861			527,443
Asset retirement obligations	88,378			81,544
Noncurrent derivative instruments	8,886			3,006
Deferred income taxes	387,807			495,888
Other long-term liabilities	5,262			13,136
Total liabilities	1,595,438			1,459,221
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized	—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized; 100,327,433 shares issued at December 31, 2017 and 100,138,797 shares issued at December 31, 2016	1,003			1,001
Premium on capital stock	1,388,082			1,372,569
Retained earnings	2,185,161			1,878,503
Accumulated other comprehensive income, net of tax
Postretirement plans	380			1,405
Deferred compensation plan	2,681			2,261
Treasury stock, at cost; 3,192,252 shares and 3,125,715 shares at December 31, 2017 and 2016, respectively	(138,850		)	(135,137		)
Total shareholders’ equity	3,438,457			3,120,602
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,033,895		$	4,579,823

The accompanying Notes to Financial Statements are an integral part of these statements.

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS



Years ended December 31, (in thousands, except share data)	2017			2016			2015

Revenues
Oil, natural gas liquids and natural gas sales	$	987,438		$	621,366		$	763,261
Gain (loss) on derivative instruments, net	(26,393		)	(88,477		)	115,293
Total revenues	961,045			532,889			878,554
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production	183,697			171,714			228,380
Production and ad valorem taxes	59,447			42,938			57,380
Depreciation, depletion and amortization	483,376			447,961			593,789
Asset impairment	1,671			220,652			1,292,308
Exploration	10,075			5,415			14,878
General and administrative (including stock-based compensation of $15,402, $19,641 and $12,910 for the years ended December 31, 2017, 2016 and 2015, respectively)	84,823			95,689			149,132
Accretion of discount on asset retirement obligations	5,831			6,672			7,108
Gain on sale of assets and other, net	(13,011		)	(246,922		)	(26,570		)
Total operating costs and expenses	815,909			744,119			2,316,405
Operating Income (Loss)	145,136			(211,230		)	(1,437,851		)
Other Income (Expense)
Interest expense	(38,366		)	(36,899		)	(43,108		)
Other income	617			978			223
Total other expense	(37,749		)	(35,921		)	(42,885		)
Income (Loss) Before Income Taxes	107,387			(247,151		)	(1,480,736		)
Income tax benefit	(199,441		)	(79,638		)	(535,005		)
Net Income (Loss)	$	306,828		$	(167,513	)	$	(945,731	)

Diluted Earnings Per Average Common Share	$	3.14		$	(1.77	)	$	(12.43	)
Basic Earnings Per Average Common Share	$	3.16		$	(1.77	)	$	(12.43	)
Diluted Average Common Shares Outstanding	97,707,408			94,475,797			76,078,371
Basic Average Common Shares Outstanding	97,182,477			94,475,797			76,078,371

The accompanying Notes to Financial Statements are an integral part of these statements.

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



Years ended December 31, (in thousands)	2017			2016			2015

Net Income (Loss)	$	306,828		$	(167,513	)	$	(945,731	)
Other comprehensive income (loss):
Pension and postretirement plans:
Amortization of prior service cost, net of tax of ($114), ($176) and $0, respectively	(340		)	(289		)	—
Amortization of net (gain) loss, including settlement costs, net of tax of $2, $1,168 and $10,676, respectively	8			1,890			19,828
Current period change in fair value of pension and postretirement plans, net of tax of ($233), ($279), and $1,779, respectively	(693		)	(459		)	3,305
Total pension and postretirement plans	(1,025		)	1,142			23,133
Comprehensive Income (Loss)	$	305,803		$	(166,371	)	$	(922,598	)

The accompanying Notes to Financial Statements are an integral part of these statements.

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY



	Common Stock			Premium on Capital Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Deferred Compensation Plan			Treasury Stock			Total Shareholders’ Equity
(in thousands, except share data)	Number of Shares	Par Value
BALANCE DECEMBER 31, 2014	75,875,711	$	759	$	564,438		$	2,997,821		$	(22,870	)	$	2,862		$	(128,406	)	$	3,414,604
Net loss							(945,731		)										(945,731		)
Other comprehensive income										23,133									23,133
Purchase of treasury shares, net (73,206 shares)																(4,723		)	(4,723		)
Shares issued for:
Stock offering	5,700,000	57		398,563															398,620
Employee benefit plans	194,450	2		6,737															6,739
Deferred compensation obligation													(897		)	897			—
Stock-based compensation				8,228															8,228
Tax benefit from employee stock plans				1,064															1,064
Cash dividends - $0.08 per share							(6,074		)										(6,074		)
BALANCE DECEMBER 31, 2015	81,770,161	818		979,030			2,046,016			263			1,965			(132,232		)	2,895,860
Net loss							(167,513		)										(167,513		)
Other comprehensive income										1,142									1,142
Purchase of treasury shares, net (88,320 shares)																(2,609		)	(2,609		)
Shares issued for:
Stock offering	18,170,000	182		380,895															381,077
Employee benefit plans	198,636	1		6,857															6,858
Deferred compensation obligation													296			(296		)	—
Stock-based compensation				6,043															6,043
Tax expense from employee stock plans				(256		)													(256		)
BALANCE DECEMBER 31, 2016	100,138,797	1,001		1,372,569			1,878,503			1,405			2,261			(135,137		)	3,120,602
Net income							306,828												306,828
Other comprehensive loss										(1,025		)							(1,025		)
Purchase of treasury shares, net (60,762 shares)																(3,293		)	(3,293		)
Impact of adoption of ASU No. 2016-09							(170		)										(170		)
Shares issued for employee benefit plans	188,636	2		9,807															9,809
Deferred compensation obligation													420			(420		)	—
Stock-based compensation				5,706															5,706
BALANCE DECEMBER 31, 2017	100,327,433	$	1,003	$	1,388,082		$	2,185,161		$	380		$	2,681		$	(138,850	)	$	3,438,457

The accompanying Notes to Financial Statements are an integral part of these statements.

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



Years ended December 31, (in thousands)	2017			2016			2015

Operating Activities
Net income (loss)	$	306,828		$	(167,513	)	$	(945,731	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	483,376			447,961			593,789
Asset impairment	1,671			220,652			1,292,308
Accretion of discount on asset retirement obligations	5,831			6,672			7,108
Deferred income taxes	(107,737		)	(57,193		)	(539,735		)
Change in derivative fair value	17,143			76,490			233,315
Gain on sale of assets	(3,620		)	(246,393		)	(28,077		)
Stock-based compensation expense	15,402			19,641			12,910
Exploration, including dry holes	2,130			16			7,097
Other, net	(10,488		)	5,752			35,641
Net change in:
Accounts receivable	(85,465		)	38,305			117,486
Inventories	1,045			(2,948		)	(655		)
Accounts payable	4,962			404			(41,560		)
Accrued taxes/income tax receivable	(55,089		)	(17,326		)	(4,791		)
Pension and other postretirement benefit contributions	(118		)	(14,608		)	(24,848		)
Other current assets and liabilities	(6,508		)	(14,855		)	5,058
Net cash provided by operating activities	569,363			295,057			719,315
Investing Activities
Additions to oil and natural gas properties	(909,852		)	(447,028		)	(1,154,373		)
Acquisitions	(276,840		)	(147,879		)	(87,410		)
Proceeds from asset sales and sale of Alabama Gas Corporation	3,695			528,775			394,521
Purchase of short-term investments	—			—			(919,000		)
Sale of short-term investments	—			—			919,000
Net cash used in investing activities	(1,182,997		)	(66,132		)	(847,262		)
Financing Activities
Payment of dividends on common stock	—			—			(6,074		)
Issuance of common stock, net	273			381,261			399,600
Taxes paid for shares withheld	(3,293		)	(2,609		)	(4,723		)
Reduction of long-term debt	(24,000		)	—			—
Net change in credit facility	255,000			(222,500		)	(262,500		)
Tax benefit (expense) on stock compensation	—			(256		)	1,064
Net cash provided by financing activities	227,980			155,896			127,367
Net change in cash and cash equivalents	(385,654		)	384,821			(580		)
Cash and cash equivalents at beginning of period	386,093			1,272			1,852
Cash and cash equivalents at end of period	$	439		$	386,093		$	1,272

The accompanying Notes to Financial Statements are an integral part of these statements.

ENERGEN CORPORATION

NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Workforce Reduction

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Principles of Consolidation

The accompanying consolidated financial statements include Energen and its subsidiaries, principally Energen Resources, after elimination of intercompany transactions in consolidation. In the opinion of management, our consolidated financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods and as of the dates shown. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior periods’ financial statements to the current-year presentation.

B. Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of proved oil and gas reserves, periodic assessments of oil and gas properties for impairment, Energen’s obligations under its employee compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves and asset retirement obligations. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

C. Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.

D. Short-term Investments

All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2017 and 2016, Energen had no short-term investments.

E. Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in the existing accounts receivable. Energen determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. Energen had an allowance for doubtful accounts of $0.6 million at December 31, 2017 and 2016.

F. Noncurrent Income Tax Receivable

The noncurrent income tax receivable of $70.7 million , net, represents the amount of minimum tax credit which Energen anticipates will be fully refundable over the taxable years 2018 through 2021 under the Tax Cuts and Jobs Act. The minimum tax credit was previously classified as a deferred tax asset. Pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985, prior year refundable minimum tax credits are subject to sequestration. Therefore, Energen has utilized the 2018 sequestration rate of 6.6 percent to estimate the portion of the refundable credit which will not be received in each of the taxable years 2018-2021 and has recorded the receivable net of this $5.0 million estimate.

G. Inventory

Inventories consist primarily of tubular goods and other oilfield equipment used in our operations and are stated at the lower of cost or net realizable, on a weighted average cost basis. Energen had an inventory valuation allowance of $0.9 million and $0.7 million at December 31, 2017 and 2016, respectively.

H. Oil and Natural Gas Operations

Operating Revenues: Energen utilizes the sales method of accounting to recognize oil, natural gas liquids and natural gas production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining proved reserves for such property. Energen had no significant production imbalances at December 31, 2017 and 2016 .

Property and Related Depletion: Energen follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, natural gas liquids and natural gas reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Energen capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, we continue to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in proved properties in the balance sheets. If the exploratory well is determined to be a dry well, the costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.

Asset Impairments: Oil and natural gas proved properties periodically are assessed for possible impairment on a field-by-field basis using the estimated undiscounted future cash flows. Energen monitors its oil and natural gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected production performance. If a material event occurs, we make an estimate of undiscounted future cash flows to determine whether the asset is impaired. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. If the asset is impaired, Energen will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows and sale agreements and similar support as applicable.

Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimates and can have a positive or negative impact on our need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact Energen’s ongoing impairment assessments.

Energen also may recognize impairments of capitalized costs for unproved properties. These capitalized costs are periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes in economic factors and potential shifts in business strategy employed by management. We consider a combination of geologic and economic factors to evaluate the need for impairment of these costs.

Acquisitions: Energen recognizes all acquisitions at fair value. Energen estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. Energen uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in general and administrative expense on the consolidated statements of operations.

Held for Sale Properties: Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. As of December 31, 2017 and 2016, Energen had no assets classified as held for sale.

I. Derivative Commodity Instruments

We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps, options and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are accounted for as mark-to-market transactions with gains and losses reported in gain (loss) on derivative instruments, net. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows. The Company’s physical contracts qualify as normal purchase and normal sales contracts.

Energen enters into three-way collars which are a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price, above the sold put, that the Company will receive for the contracted volumes. The Company will receive the market price for the contracted volumes if the market price is between the sold call and the purchased put. If, however, the market price for the commodity falls below the sold put strike price, the minimum price that the Company will receive for the contracted volumes equals the market price plus the excess of the purchased put strike price over the sold put strike price.

The majority of our counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes.

J. Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable, accounts receivable (net of allowance), derivative commodity instruments, postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). In determining fair value, we use various valuation approaches and classify all assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own assumptions about the assumptions other market participants would use in pricing the asset or liability based on the best information available in the circumstances. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The hierarchy is broken down into three levels based on the observability of inputs as follows:


Level 1 -	Unadjusted quoted prices in active markets for identical assets or liabilities;


Level 2 -	Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date; and


Level 3 -	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The fair value of Energen’s derivative commodity instruments is determined using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. Our OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which we are able to substantiate fair value through direct or indirect observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps and options priced in reference to NYMEX oil and natural gas prices, basin specific gas hedges and gas basis. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include oil basis and natural gas liquids swaps. We consider the frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While Energen does not have access to the specific assumptions used in its counterparties’ valuation models, we maintain communications with our counterparties and discuss pricing practices. Further, we corroborate the fair value of our transactions by comparison of market-based price sources.

Postretirement plan assets include cash and mutual funds. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds.

K. Stock-Based Compensation

Energen recognizes all share-based compensation awards in general and administrative expense on the consolidated statement of operations over the requisite vesting period. Equity awards are measured at fair value as of the date of grant. Awards that are settled in cash are classified as liabilities and re-measured at fair value at the end of each reporting period. We recognize all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. Prior to the adoption of Accounting Standard Update (ASU) No. 2016-09, Improvements to Employee Share-Based Payment Accounting, on January 1, 2017, forfeitures were estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates and Energen utilized the long-form method of calculating the available pool of windfall tax benefit. Upon adoption of this new guidance, the Company recognizes forfeitures as they occur and all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in our consolidated statements of operations as a discrete item in the reporting period in which they occur. For the years ended December 31, 2017, 2016 and 2015, we recognized an excess tax benefit of $0.4 million , tax expense of $0.3 million and an excess tax benefit of $1.1 million , respectively, related to our stock-based compensation.

L. Environmental Costs

Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.

M. Income Taxes

Energen uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. Energen and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.

N. Earnings Per Share (EPS)

Energen’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities.

O. Employee Benefit Plans

Postretirement Benefit Plans: Energen provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for Energen. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability. For these plans, certain financial assumptions are used in determining Energen’s projected benefit obligation. These assumptions are examined periodically by Energen, and any required changes are reflected in the subsequent determination of projected benefit obligations.

Energen calculates periodic expense for the postretirement benefit plans on an actuarial basis and the net funded status is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. The benefit obligation is the accumulated postretirement benefit obligation. Energen measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.

For our postretirement plans, we selected a yield curve comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments.

The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. Energen considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.

Plan Termination: Energen terminated its qualified defined benefit pension plan on January 31, 2015 and distributed benefits in December 2015. In February 2018, Energen received notice that the Pension Benefit Guaranty Corporation had completed its audit of the termination of the pension plan and of the distribution of plan assets noting no exceptions.

3. LONG-TERM DEBT

Long-term debt consisted of the following:



(in thousands)	December 31, 2017		December 31, 2016
Credit facility, due August 30, 2019	$	255,000	$	—
7.40% Medium-term Notes, Series A, due July 24, 2017	—		2,000
7.36% Medium-term Notes, Series A, due July 24, 2017	—		15,000
7.23% Medium-term Notes, Series A, due July 28, 2017	—		2,000
7.32% Medium-term Notes, Series A, due July 28, 2022	20,000		20,000
7.60% Medium-term Notes, Series A, due July 26, 2027	—		5,000
7.35% Medium-term Notes, Series A, due July 28, 2027	10,000		10,000
7.125% Medium-term Notes, Series B, due February 15, 2028	100,000		100,000
4.625% Notes, due September 1, 2021	400,000		400,000
Total	785,000		554,000
Less amounts due within one year	—		24,000
Less unamortized debt discount	360		387
Less unamortized debt issuance costs	1,779		2,170
Total	$	782,861	$	527,443

The aggregate maturities of Energen’s long-term debt as of December 31, 2017 are as follows:



Years ending December 31, (in thousands)
2018	2019	2020	2021	2022	Thereafter
$—	$255,000	$—	$400,000	$20,000	$110,000

On January 23, 2017, Energen redeemed the $2 million of 7.40% Medium-term Notes, Series A, due July 24, 2017 and $5 million of 7.60% Medium-term Notes, Series A, due July 26, 2027. The Company also had $17.0 million of scheduled reductions in long-term debt in July 2017.

The debt agreements of Energen contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. None of the debt agreements have events of default based on credit ratings.

Our 4.625% Notes due September 1, 2021 include change in control provisions that would be triggered in a variety of change in control events including, but not limited to, the election to our Board of a majority of directors who are not Continuing Directors. As defined in the notes, a Continuing Director is a director who (1) was a member of the Board on the date of the initial issuance of the notes; or (ii) was nominated for election or elected to the Board with the approval of a majority of the Continuing Directors who were members of the Board at the time of such nomination or election.

Credit Facility: On September 2, 2014, Energen entered into a five -year syndicated secured credit facility with domestic and foreign lenders. On October 25, 2016, the borrowing base and aggregate commitments were reaffirmed at $1.05 billion each with no changes in association with the semi-annual redetermination required under the agreement. On April 21, 2017, the borrowing base was increased to $1.4 billion . The aggregate commitments under the credit facility did not change and remained at $1.05 billion . On November 9, 2017, the borrowing base was increased to $1.7 billion . The aggregate commitments under the credit facility did not change and remained at $1.05 billion . Energen’s obligations under the syndicated credit facility are unconditionally

guaranteed by Energen Resources. The credit facility is collateralized by certain assets of Energen and Energen Resources, including a pledge of equity interests in subsidiaries of Energen other than Energen Resources, by mortgages on substantially all of Energen Resources’ oil and natural gas properties and by the pledge of Energen’s and Energen Resources’ deposit accounts, securities accounts and commodity accounts (other than de minimus accounts and excluded accounts). The current credit facility qualifies for classification as long-term debt on the consolidated balance sheets. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other non-cash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0 ; and to maintain a ratio of consolidated current assets (adjusted to include amounts available for borrowings and exclude non-cash derivative instruments) to consolidated current liabilities (adjusted to exclude maturities under the credit facility and non-cash derivative instruments) greater than or equal to 1.0 to 1.0. We are also bound by covenants which limit our ability to incur additional indebtedness, make certain distributions or alter our corporate structure. Energen may not pay dividends if an event of default exists, if the payment would result in an event of default, or if availability is less than 10 percent of the loan limit under the credit facility. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. In addition, the terms of our credit facility limit the amount we can borrow to a borrowing base amount which is determined by our lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria including commodity price outlook. The borrowing base amount is subject to redetermination semi-annually and for event-driven unscheduled redeterminations. Our next scheduled redetermination is April 1, 2018.

Under Energen’s credit facility, a cross default provision provides that any debt default of more than $75 million by Energen or Energen Resources will constitute an event of default by Energen.

Upon an uncured event of default under the credit facility, all amounts owing under the credit facility, if any, depending on the nature of the event of default will automatically, or may upon notice by the administrative agent or the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. Energen was in compliance with the terms of its credit facility as of December 31, 2017 .

The following is a summary of information relating to Energen’s credit facility:



(in thousands)	December 31, 2017		December 31, 2016
Credit facility outstanding	$	255,000	$	—
Available for borrowings	795,000		1,050,000
Total borrowing commitments	$	1,050,000	$	1,050,000



Years ended December 31, (in thousands)	2017			2016			2015
Maximum amount outstanding at any month-end	$	285,500		$	214,500		685,000
Average daily amount outstanding	$	131,822		$	33,642		358,929
Weighted average interest rates based on:
Average daily amount outstanding	2.54		%	1.72		%	1.60	%
Amount outstanding at year-end	2.77		%	—		%	1.64	%

Energen’s total interest expense was $38.4 million , $36.9 million and $43.1 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Energen’s total interest expense for the years ended December 31, 2017, 2016 and 2015 included amortization of debt issuance costs related to long-term debt, including our credit facility, of $3.3 million , $3.3 million and $3.3 million , respectively. There was no capitalized interest expense for the year ended December 31, 2017 and capitalized interest for the year ended December 31, 2015 was not significant. Capitalized interest expense was $0.1 million for the year ended December 31, 2016. At December 31, 2017, Energen paid commitment fees on the unused portion of available credit facility at a current annual rate of 30 basis points per annum. Energen paid commitment fees of $2.8 million , $3.4 million and $4.1 million for the years ended December 31, 2017, 2016 and 2015, respectively.

4. INCOME TAXES

The components of Energen’s income taxes consisted of the following:



Years ended December 31, (in thousands)	2017			2016			2015
Current taxes:
Federal	$	(92,236	)	$	(23,277	)	$	3,972
State	532			832			758
Total current	(91,704		)	(22,445		)	4,730
Taxes deferred:
Federal	(113,412		)	(62,205		)	(513,187		)
State	5,675			5,012			(26,548		)
Total deferred	(107,737		)	(57,193		)	(539,735		)
Total income tax benefit	$	(199,441	)	$	(79,638	)	$	(535,005	)

Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows:



(in thousands)	December 31, 2017			December 31, 2016
	Noncurrent			Noncurrent
Deferred tax assets:
Minimum tax credit	$	—		$	64,203
Insurance and other accruals	1,455			3,151
Compensation accruals	6,645			13,895
Deferred compensation and other costs	2,605			5,401
Derivative instruments	16,032			22,402
Federal net operating losses and other carryforwards	2,350			—
State net operating losses and other carryforwards	15,642			12,947
Other	338			535
Total deferred tax assets	45,067			122,534
Valuation allowance	(7,710		)	(5,735		)
Total deferred tax assets	37,357			116,799
Deferred tax liabilities:
Depreciation and basis differences	417,376			603,324
Other comprehensive income	223			854
Other	7,565			8,509
Total deferred tax liabilities	425,164			612,687
Net deferred tax liabilities	$	(387,807	)	$	(495,888	)

Energen files a consolidated federal income tax return with all of its subsidiaries. Energen has a federal net operating loss generated in the current year of $46 million , which the Company intends to carry back $38 million and utilize in the 2015 tax year. The remaining $8.0 million federal net operating loss carryforward will expire in 2037. Energen made a reclassification of approximately $6.8 million between income tax receivable and deferred tax assets to reflect the impact of the federal net operating loss carryback. In addition, this federal net operating loss carryback and the final 2016 carryback claim filed in 2017 will generate an additional minimum tax credit carryforward of $13 million . As of December 31, 2017, the amount of minimum tax credit which Energen anticipates will be fully refundable over the taxable years 2018 through 2021 under the Tax Cuts and Jobs Act is $75.7 million . Energen reclassed the minimum tax credit to a noncurrent income tax receivable on the balance sheet and recorded a $5 million

income tax writedown for the impact of sequestration of the refundable credit as discussed further in Note 2, Summary of Significant Accounting Policies.

Energen Resources has $301 million of state net operating loss carryforwards which will expire beginning in 2026 through 2037. Energen Resources has a valuation allowance recorded against deferred tax assets of $7.7 million arising from certain of these state net operating losses and other state deferred tax assets that are not expected to be realized through reversals of its existing taxable temporary differences. Energen intends to fully reserve these assets until it is determined that deferred tax assets can be realized through future taxable income in the respective state taxing jurisdictions. No other valuation allowance with respect to deferred taxes is deemed necessary as Energen anticipates generating adequate future taxable income from the reversals of its existing taxable temporary differences to realize the benefits of all remaining deferred tax assets on the consolidated balance sheets.

Total income tax expense from operations differs from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:



Years ended December 31, (in thousands)	2017			2016			2015
Income tax expense (benefit) at statutory federal income tax rate	$	37,585		$	(86,503	)	$	(518,258	)
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	3,235			925			(15,417		)
Impact of state law changes	(12		)	(9		)	(3,075		)
Impact of state deferred tax revaluation on San Juan properties	—			(153		)	(1,241		)
Change in deferred tax valuation allowance	1,975			2,500			1,305
Impact of sequestration on minimum tax credit refund	4,998			—			—
Impact of corporate rate reduction due to the Tax Cuts and Jobs Act (remeasurement of deferred taxes)	(247,844		)	—			—
Other, net	622			3,602			1,681
Total income tax benefit	$	(199,441	)	$	(79,638	)	$	(535,005	)
Effective income tax rate (%)	(185.72		)	32.22			36.13

The Tax Cuts and Jobs Act was signed into law on December 22, 2017. The change in tax rates and tax law are accounted for in the period of enactment. Accordingly, Energen recognized the impact of the corporate rate reduction from 35 percent to 21 percent for tax years beginning after December 31, 2017, as a discrete event in the fourth quarter of 2017 and remeasured its deferred tax assets and liabilities through income tax expense. The remeasurement of Energen’s net deferred tax liability resulted in a provisional income tax benefit of $247.8 million . As discussed further in the summary of significant accounting policies note to the financial statements, Energen recorded a $5.0 million income tax writedown for the impact of sequestration of the refundable minimum tax credit provision. The provisions of the Tax Cuts and Jobs Act were considered in the assessment of the change in deferred tax valuation allowance of $2.0 million . Other provisions of the Tax Cuts and Jobs Act did not have a material impact on Energen’s effective tax rate and have been included in the other, net line item above.

Under SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), provisional amounts must be recorded for certain income tax effects of the Tax Cuts and Jobs Act for which the accounting under Accounting Standard Codification 740 is incomplete but a reasonable estimate can be determined. Energen recorded a provisional estimate of $0.4 million deferred income tax expense with respect to the IRC Section 162(m) limitation and associated compensation-related deferred tax assets. Energen is awaiting guidance from the IRS with respect to transition relief on certain written binding contracts which were in effect on November 2, 2017. Any adjustment to this provisional estimate will be recorded in the period when further guidance is issued but no later than the fourth quarter of 2018.

In addition to other changes in state apportionment reflected in the state income taxes, net of federal income tax benefit above, Energen recognized $0.2 million and $1.2 million of income tax benefit during 2016 and 2015, respectively, as a result of re-measuring its state deferred tax liabilities. This re-measurement reflected the state apportionment changes related to certain San Juan Basin properties designated as held for sale as of December 31, 2015.

A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:



(in thousands)
Balance as of December 31, 2014	$	17,530
Additions based on tax positions related to the current year	2,378
Reductions based on tax positions related to the current year	(6,589		)
Reductions for tax positions of prior years	(345		)
Lapse of statute of limitations	(1,785		)
Balance as of December 31, 2015	11,189
Additions based on tax positions related to the current year	2,936
Additions for tax positions of prior years	1,484
Reductions for tax positions of prior years	(99		)
Lapse of statute of limitations	(1,300		)
Balance as of December 31, 2016	14,210
Additions based on tax positions related to the current year	1,309
Reductions for tax positions of prior years	(2,733		)
Lapse of statute of limitations	(4,416		)
Balance as of December 31, 2017	$	8,370

The amount of unrecognized tax benefits at December 31, 2017 that would favorably impact Energen’s effective tax rate, if recognized, is $4.2 million . Energen recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2017 , 2016 and 2015 , Energen recognized approximately $31,000 of income, $101,000 of expense and $2,000 of income for interest (net of tax benefit) and penalties, respectively. Energen had approximately $0.3 million for the payment of interest (net of tax benefit) and penalties accrued at both December 31, 2017 and 2016 , respectively.

Energen’s tax returns for years 2014-2016 remain open and subject to examination by the IRS and major state taxing jurisdictions. Energen is currently under IRS examination of its federal consolidated income tax returns for 2014 and 2016. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, Energen does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

5. EMPLOYEE BENEFIT PLANS

Plan Terminations: Energen terminated its qualified defined benefit pension plan on January 31, 2015 and distributed benefits in December 2015. In February 2018, Energen received notice that the Pension Benefit Guaranty Corporation had completed its audit of the termination of the pension plan and of the distribution of plan assets noting no exceptions.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans were partially made in the first quarter of 2015 with the remainder of approximately $14.5 million paid in the first quarter of 2016. The Company expects to make no additional benefit payments with respect to the termination of the non-qualified supplemental retirement plans. Certain annuities associated with our non-qualified supplemental retirement plans remain of approximately $1.0 million and $1.1 million and are included in other current liabilities and other long-term liabilities on the consolidated balance sheets at December 31, 2017 and 2016, respectively.

Benefit Obligations: The following table sets forth the funded status of the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in Energen’s consolidated financial statements.



As of December 31, (in thousands)	2017			2016
	Postretirement Benefits
Accumulated benefit obligation
Benefit obligation:
Balance at beginning of period	$	5,447		$	6,488
Service cost	70			94
Interest cost	227			223
Actuarial loss	413			917
Plan amendments	—			(422		)
Curtailment gain	—			(477		)
Benefits paid	(221		)	(1,376		)
Balance at end of period	$	5,936		$	5,447
Plan assets:
Fair value of plan assets at beginning of period	$	9,066		$	10,369
Actual return (loss) on plan assets*	(263		)	73
Benefits paid	(221		)	(1,376		)
Fair value of plan assets at end of period	8,582			9,066
Funded status of plans	$	2,646		$	3,619



Amounts recognized on consolidated balance sheets:
Noncurrent assets recognized	$	2,646		$	3,619
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes	$	(1,680	)	$	(2,111	)
Net actuarial loss, net of taxes	1,300			643
Total accumulated other comprehensive income	$	(380	)	$	(1,468	)

*Actual loss on plan assets for the year ended December 31, 2017 include $0.9 million for tax payments.

The components of net periodic benefit cost were as follows:



Years ended December 31, (in thousands)	2017			2016			2015
Pension Plans
Components of net periodic benefit cost:
Interest cost	$	—		$	—		$	816
Actuarial loss amortization	—			—			737
Settlement charge	—			3,325			29,767
Net periodic expense	$	—		$	3,325		$	31,320
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	70		$	94		$	392
Interest cost	227			223			466
Expected long-term return on assets	(249		)	(316		)	(457		)
Prior service cost amortization	(454		)	(465		)	—
Actuarial gain amortization	10			—			—
Settlement charge	—			45			—
Curtailment gain	—			(816		)	—
Net periodic (income) expense	$	(396	)	$	(1,235	)	$	401

Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows:



Years ended December 31, (in thousands)	2017			2016			2015
Pension Plans
Net actuarial gain experienced during the year	$	—		$	—		$	(394	)
Net actuarial loss recognized as expense	—			(3,352		)	(30,478		)
Total recognized in other comprehensive loss	—			(3,352		)	(30,872		)
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	925		$	682		$	(645	)
Net actuarial loss recognized as expense	(10		)	(9		)	—
Prior service cost recognized as income	—			780			—
Prior service credit during the year	—			(421		)	(4,071		)
Prior service cost amortization	454			465			—
Total recognized in other comprehensive income (loss)	$	1,369		$	1,497		$	(4,716	)

In the first quarter of 2016, Energen incurred a settlement charge of $3.3 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the three months ended March 31, 2016, Energen incurred a curtailment gain of $0.8 million in connection with the reduction in workforce.

In the year ended December 31, 2015, Energen incurred settlement charges of $27.3 million for the payment of lump sums from the qualified defined benefit pension plans. Also in the first quarter of 2015, Energen incurred a settlement charge of $2.5 million for the payment of lump sums from the non-qualified supplemental retirement plans.

Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2018 are included in the table below.



(in thousands)
Amortization of prior service credit	$	(454	)
Amortization of net actuarial loss	$	125

Energen has a long-term disability plan covering most employees. Energen had expense of $0.1 million for the year ended December 31, 2017. Energen had expense of $0.2 million for each of the years ended December 31, 2016 and 2015.

Assumptions: The weighted average rate assumptions to determine net periodic benefit costs were as follows:



Years ended December 31,	2017		2016		2015
Pension Plans
Discount rate	—		—		0.96	%
Postretirement Benefit Plans
Discount rate	4.30	%	4.37	%	4.25	%
Expected long-term return on plan assets	4.30	%	4.96	%	6.20	%

For the year ended December 31, 2015, the discount rate for the pension plans shown above represents the weighted average for the nonqualified supplemental retirement plan. As the plans were frozen as of December 31, 2014, the rate of compensation increase no longer applies for any of the plans.

The weighted average assumptions used to determine the postretirement benefit obligations at the measurement date were as follows:



Years ended December 31,	2017		2016
Discount rate	3.70	%	4.30	%

Health care costs trend rates will not have a material impact to the accumulated postretirement benefit obligation as the majority of employees will receive a fixed postretirement benefit.

Investment Strategy: For our postretirement benefit plan assets, we continue to employ a total return investment approach whereby a mix of fixed income investments and equities are used to meet future plan obligations on a long-term basis with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.

Energen seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, commodity or class of investment fund.

The Company’s weighted average plan asset allocations by asset category for postretirement benefit plans were as follows:



As of December 31,	Target		2017		2016
Asset category:
Equity securities	21	%	21	%	26	%
Debt securities	74	%	73	%	74	%
Other	5	%	6	%	—
Total	100	%	100	%	100	%

Equity securities for postretirement benefits do not include the Company’s common stock.

Plan assets included in the funded status of the postretirement benefit plans were as follows:



	December 31, 2017
(in thousands)	Level 1		Level 2		Total
United States equities	$	165	$	—	$	165
Global equities	1,673		—		1,673
Fixed income	6,224		—		6,224
Other	520		—		520
Total	$	8,582	$	—	$	8,582



	December 31, 2016
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	$	10	$	—	$	10
United States equities	180		—		180
Global equities	2,158		—		2,158
Fixed income	6,718		—		6,718
Total	$	9,066	$	—	$	9,066

Energen had no Level 3 postretirement benefit plan assets. United States equities consist of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches. Global equities are mutual funds that invest in both United States and non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles. Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.

Cash Flows: Due to restructuring of our plans, Energen no longer qualifies for benefits related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows:



(in thousands)		Postretirement Benefits
2018		$349
2019		$327
2020		$347
2021		$367
2022		$320
2023-2027		$1,597

Energen Employee Savings Plan (ESP): The Company sponsors the ESP for the benefit of substantially all employees. The ESP allows eligible employees to contribute a percentage of their annual compensation. The Company makes contributions matching a portion of the employee’s contribution and, additionally, makes employer supplemental contributions as a percentage of each employee’s compensation. Expense associated with Energen contributions to the ESP was $3.2 million , $3.3 million and $5.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively.

2017 Change in Control Severance Pay Plan

In November 2017, Energen adopted the Change in Control Severance Pay Plan which provides for certain severance payments to non-officer employees of Energen Corporation in the event of an involuntary termination of employment other than for cause or a voluntary termination for good reason within one year following any Change in Control. Change in Control, as used in the

Plan, has the same definition included in Energen’s Severance Compensation Agreements with named executive officers. The Plan has an initial term of three years, with an automatic one-year extension each anniversary, beginning with the second anniversary of the effective date of the Plan, absent Company notification that it will not be extended. The Plan may not be terminated (nor may any amendment which adversely affects rights of participants under the Plan become effective) during the one-year period following a Change in Control.

6. COMMON STOCK PLANS

Stock Incentive Plan: The Stock Incentive Plan provides for the grant of performance share awards and restricted stock units and restricted stock. The Stock Incentive Plan also provides for the grant of non-qualified stock options and incentive stock options to officers and key employees. Under the Stock Incentive Plan, established in 1997, 3,327,232 shares of Energen common stock are reserved for issuance, adjusted for stock splits, with 1,444,057 available for future grants as of December 31, 2017 .

Performance Share Awards: The Stock Incentive Plan provides for the grant of performance share awards to eligible employees based on predetermined Energen performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Energen common stock.

A summary of performance share award activity as of December 31, 2017 , and transactions during the years ended December 31, 2017, 2016 and 2015 is presented below:



	Performance Share Awards
	Shares		Weighted Average Price
Nonvested at December 31, 2014	212,968		$	71.53
Granted (three-year vesting period)	120,372		83.94
Vested and paid	(77,257	)	61.36
Nonvested at December 31, 2015	256,083		80.43
Granted (three-year vesting period)	167,016		25.34
Vested and paid	(74,176	)	63.88
Forfeited	(12,481	)	72.30
Nonvested at December 31, 2016	336,442		57.03
Granted (two-year vesting period)	3,116		96.54
Granted (three-year vesting period)	137,084		66.89
Vested and paid	(59,530	)	93.52
Forfeited	(17,075	)	48.55
Nonvested at December 31, 2017	400,037		$	55.65

Energen recorded expense of $7.4 million , $6.2 million and $6.7 million for the years ended December 31, 2017, 2016 and 2015, respectively, for performance share awards with a related deferred income tax benefit of $1.4 million , $1.2 million and $2.4 million , after consideration of certain executive compensation limits under IRC Section 162(m). As of December 31, 2017, there was $7.2 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.12 years.

Restricted Stock: In addition, the Stock Incentive Plan provides for the grant of restricted stock and restricted stock units (restricted stock awards) which have been valued based on the quoted market price of Energen’s common stock at the date of grant. Restricted stock awards vest within three years from grant date. A summary of restricted stock award activity as of December 31, 2017 , and transactions during the years ended December 31, 2017 , 2016 and 2015 is presented below:



	Restricted Stock
	Awards		Weighted Average Price
Nonvested at December 31, 2014	99,574		$	59.60
Restricted stock units granted	99,814		65.15
Vested	(14,446	)	53.20
Nonvested at December 31, 2015	184,942		63.09
Restricted stock units granted	197,473		29.89
Vested	(56,337	)	54.70
Forfeited	(435	)	40.73
Nonvested at December 31, 2016	325,643		44.44
Restricted stock units granted	128,272		52.42
Vested	(45,576	)	65.68
Forfeited	(2,803	)	44.68
Nonvested at December 31, 2017	405,536		$	44.58

Energen recorded expense of $6.7 million , $5.3 million and $6.0 million for the years ended December 31, 2017 , 2016 and 2015 , respectively, related to restricted stock awards, with a related deferred income tax benefit of $1.3 million , $1.1 million and $1 million , respectively, after consideration of certain executive compensation limits under IRC Section 162(m). As of December 31, 2017 , there was $2.3 million of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 1.18 years.

Stock Options: The Stock Incentive Plan provides for the grant of non-qualified stock options, incentive stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Energen common stock at not less than the fair market value on the date the option was granted. The sale or transfer of the shares is limited during certain periods. All outstanding options are non-qualified, are fully vested and expire 10 years from the grant date.

A summary of stock option activity as of December 31, 2017 , and transactions during the years ended December 31, 2017 , 2016 and 2015 are presented below:



	Stock Options
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2014	757,071		$	54.88
Exercised	(23,680	)	41.42
Outstanding at December 31, 2015	733,391		55.32
Exercised	(22,490	)	44.60
Outstanding at December 31, 2016	710,901		55.66
Exercised	(6,052	)	48.36
Expired	(27,284	)	58.40
Outstanding at December 31, 2017	677,565		$	55.61
Exercisable at December 31, 2015	622,156		$	53.80
Exercisable at December 31, 2016	676,271		$	54.79
Exercisable at December 31, 2017	677,565		$	55.61

In 2017, Energen’s stock option expense was not significant. Energen recorded stock option expense of $0.1 million and $0.4 million during the years ended December 31, 2016 and 2015 , respectively, with a related deferred tax benefit of $44,000 and $0.1 million , respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2017 , was $17,271 . During the year ended December 31, 2017 , Energen received cash of $0.3 million from the exercise of stock options. The total intrinsic value for outstanding options as of December 31, 2017 , was $3.1 million , all of which were exercisable. The fair value of options vested for the year ended December 31, 2017 was $1.0 million . As of December 31, 2017 , there was no unrecognized compensation cost related to outstanding nonvested stock options.

The following table summarizes options outstanding as of December 31, 2017 :



Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$60.56	48,560	0.07 years
$29.79	21,791	1.00 year
$46.69	26,481	2.00 years
$54.99	101,285	3.00 years
$54.11	254,426	4.00 years
$48.36	117,446	5.00 years
$80.48	3,686	5.79 years
$72.39	101,451	6.00 years
$79.63	2,439	6.00 years
$29.79-$80.48	677,565	3.88 years

All stock options are exercisable as of December 31, 2017 .

Stock Appreciation Rights Plan: The Energen Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Energen common stock. Officers of Energen are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are remeasured each reporting period until settlement. These awards have a three year requisite service period.

A summary of stock appreciation rights activity as of December 31, 2017 , and transactions during the years ended December 31, 2017 , 2016 and 2015 are presented below:



	Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2014	275,150		$	52.96
Exercised/forfeited	(10,283	)	55.18
Outstanding at December 31, 2015	264,867		52.88
Exercised/forfeited	(12,338	)	61.51
Outstanding at December 31, 2016	252,529		52.46
Exercised/forfeited	(12,285	)	50.43
Outstanding at December 31, 2017	240,244		$	52.56

Energen issued the following awards with stock appreciation rights. Energen uses the Black-Scholes pricing model to calculate the fair values of the rights awarded. Certain stock appreciation rights have been modified subsequent to the original grant date. For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2017 :



Grant date	1/22/2014	1/22/2014	1/22/2014	1/24/2013	1/24/2013	1/24/2013
		(modified)	(modified)		(modified)	(modified)
Awards granted	46,710	15,517	522	63,436	20,218	768
Fair market value of award	$11.53	$6.92	$4.93	$18.89	$16.21	$14.43
Expected life of award	3.03 years	1.63 years	1.13 years	2.53 years	1.63 years	1.13 years
Risk-free interest rate	1.98%	1.86%	1.79%	1.92%	1.86%	1.79%
Annualized volatility rate	38.1%	38.1%	38.1%	38.1%	38.1%	38.1%
Dividend yield	—%	—%	—%	—%	—%	—%



Grant date	1/24/2013	1/26/2011	1/26/2011	1/27/2010	1/28/2009	2/4/2008
	(modified)		(modified)
Awards granted	3,578	182,199	7,785	171,749	305,257	67,093
Fair market value of award	$11.69	$12.54	$7.64	$15.12	$28.06	$0.25
Expected life of award	0.50 years	1.54 years	0.50 years	1.04 years	0.54 years	0.05 years
Risk-free interest rate	1.53%	1.86%	1.53%	1.77%	1.54%	1.25%
Annualized volatility rate	38.1%	38.1%	38.1%	38.1%	38.1%	38.1%
Dividend yield	—%	—%	—%	—%	—%	—%

Income associated with stock appreciation rights of $0.5 million and $3.2 million was recorded for the years ended December 31, 2017 and 2015, respectively. Expense associated with stock appreciation rights of $2.6 million was recorded for the year ended 2016. During the year ended December 31, 2017 , the total intrinsic value of stock appreciation rights exercised was $34,000 . During the year ended December 31, 2017 , Energen paid $23,000 in settlement of stock appreciation rights.

Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units which may include market conditions. Officers of Energen are not eligible to participate in this Plan. These awards are liability awards which are remeasured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions are valued based on Energen’s stock price at the end of the period adjusted to remove the present value of future dividends.

A summary of Petrotech unit activity as of December 31, 2017 , and transactions during the years ended December 31, 2017 , 2016 and 2015 are presented below:



	Petrotech Incentive Plan
	Shares
Outstanding at December 31, 2014	213,870
Granted (three-year vesting period)	128,519
Granted (two-year vesting period)	297
Granted (16 month vesting period)	1,648
Paid	(78,430	)
Forfeited	(22,158	)
Outstanding at December 31, 2015	243,746
Paid	(67,392)
Forfeited	(32,111)
Outstanding at December 31, 2016	144,243
Paid	(55,973)
Forfeited	(4,095)
Outstanding at December 31, 2017	84,175

Energen recognized expense of $1.8 million , $5.4 million and $3.0 million during 2017 , 2016 and 2015 , respectively, related to these units.

1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allows officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of Energen’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. Energen has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of our creditors. Amounts earned under the 1997 Deferred Compensation Plan and invested in Energen common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the consolidated statements of shareholders’ equity. As of December 31, 2017 , there were 568,688 shares reserved for issuance from the 1997 Deferred Compensation Plan.

1992 Energen Corporation Directors Stock Plan: In 1992 Energen adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Energen common stock. Under the Plan, 14,000 shares, 25,470 shares and 11,550 shares were awarded during the years ended December 31, 2017 , 2016 and 2015 , respectively, leaving 76,904 shares reserved for issuance as of December 31, 2017 .

Stock Repurchase Authorization: By resolution adopted October 22, 2014, the Board of Directors authorized Energen to repurchase up to 3,600,000 shares of Energen common stock. The resolution does not have an expiration date and does not limit Energen’s authorization to acquire shares in connection with tax withholdings and payment of exercise price on stock compensation plans. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2017, 2016 and 2015. As of December 31, 2017 , a total of 3,373,161 shares remain authorized for future repurchase. Energen also acquires shares in connection with withholdings from participants to satisfy tax obligations under Energen’s stock compensation plans. For the years ended December 31, 2017 , 2016 and 2015 , Energen acquired 60,762 shares, 88,320 shares and 73,126 shares, respectively, in connection with its stock compensation plans.

7. DERIVATIVE COMMODITY INSTRUMENTS

The following table details gain (loss) on derivative instruments, net, as follows:



Years ended December 31, (in thousands)	2017			2016			2015
Open non-cash mark-to-market losses on derivative instruments	$	(10,759	)	$	(71,190	)	$	(281,752	)
Closed gains (losses) on derivative instruments	(15,634		)	(17,287		)	397,045
Gain (loss) on derivative instruments, net	$	(26,393	)	$	(88,477	)	$	115,293

Open and closed derivative commodity instruments in the table above were not designated as hedging instruments on the consolidated statements of operations.

The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets:



(in thousands)	December 31, 2017
										Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value			Gross Amounts Offset in the Balance Sheets			Net Amounts Presented in the Balance Sheets			Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	1,758		$	(1,758	)	$	—		$	—	$	—	$	—
Noncurrent derivative instruments	42			(42		)	—			—		—		—
Total derivative assets	$	1,800		$	(1,800	)	$	—		$	—	$	—	$	—
Liabilities
Derivative instruments	73,137			(1,758		)	71,379			—		—		71,379
Noncurrent derivative instruments	8,928			(42		)	8,886			—		—		8,886
Total derivative liabilities	82,065			(1,800		)	80,265			—		—		80,265
Total derivatives	$	(80,265	)	$	—		$	(80,265	)	$	—	$	—	$	(80,265	)



(in thousands)	December 31, 2016
										Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value			Gross Amounts Offset in the Balance Sheets			Net Amounts Presented in the Balance Sheets			Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	1,756		$	(1,706	)	$	50		$	—	$	—	$	50
Liabilities
Derivative instruments	67,173			(1,706		)	65,467			—		—		65,467
Noncurrent derivative instruments	3,006			—			3,006			—		—		3,006
Total derivative liabilities	70,179			(1,706		)	68,473			—		—		68,473
Total derivatives	$	(68,423	)	$	—		$	(68,423	)	$	—	$	—	$	(68,423	)

As of December 31, 2017, Energen entered into the following transactions for 2018 and subsequent years:



Production Period	Description	Total Hedged Volumes		Average Contract Price
Oil
2018	NYMEX Three-Way Collars	13,500	MBbl
	Ceiling sold price (call)			$60.04 Bbl
	Floor purchased price (put)			$45.47 Bbl
	Floor sold price (put)			$35.47 Bbl
2019	NYMEX Three-Way Collars	4,680	MBbl
	Ceiling sold price (call)			$60.84 Bbl
	Floor purchased price (put)			$45.00 Bbl
	Floor sold price (put)			$35.00 Bbl
Oil Basis Differential
2018	WTI/WTI Basis Swaps	10,800	MBbl	$(1.01) Bbl
2019	WTI/WTI Basis Swaps	4,680	MBbl	$(0.44) Bbl
Natural Gas Liquids
2018	Liquids Swaps	105.8	MMGal	$0.59 Gal
2019	Liquids Swaps	25.2	MMGal	$0.66 Gal
Natural Gas
2018	Basin Specific Swaps - Permian	3.6	Bcf	$2.56 Mcf
WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

As of December 31, 2017 , the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2019.

8. FAIR VALUE MEASUREMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Energen classifies the fair value of multiple derivative instruments executed under master netting arrangements as net derivative assets and liabilities. The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis:



	December 31, 2017
(in thousands)	Level 2			Level 3			Total
Liabilities
Derivative instruments	$	43,241		$	28,138		$	71,379
Noncurrent derivative instruments	7,736			1,150			8,886
Total liabilities	50,977			29,288			80,265
Net derivative liability	$	(50,977	)	$	(29,288	)	$	(80,265	)



	December 31, 2016
(in thousands)	Level 2			Level 3			Total
Assets
Derivative instruments	$	50		$	—		$	50
Total assets	50			—			50
Liabilities
Derivative instruments	57,927			7,540			65,467
Noncurrent derivative instruments	1,694			1,312			3,006
Total liabilities	59,621			8,852			68,473
Net derivative liability	$	(59,571	)	$	(8,852	)	$	(68,423	)

Energen prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its Level 3 instruments. We estimate that a 10 percent increase or decrease in commodity prices would result in an approximate $9.2 million change in the fair value of open Level 3 derivative contracts and to our results of operations.

The table below sets forth a summary of changes in the fair value of Energen’s Level 3 derivative commodity instruments as follows:



Years ended December 31, (in thousands)	2017			2016			2015
Balance at beginning of period	$	(8,852	)	$	(16,059	)	$	24,436
Realized gains (losses)	(10,121		)	(14,120		)	13,145
Unrealized gains (losses) relating to instruments held at the reporting date*	(19,027		)	5,745			(40,495		)
Settlements during period	8,712			14,120			(13,145		)
Transfer out of Level 3	—			1,462			—
Balance at end of period	$	(29,288	)	$	(8,852	)	$	(16,059	)

*Includes losses of $26.6 million , $8.9 million and $16.1 million related to open contracts held at the reporting date for the years ended December 31, 2017, 2016 and 2015, respectively.

Changes in Fair Value Levels: The availability of observable market data is monitored to assess the appropriate classification for financial instruments within the fair value hierarchy. Changes in economic conditions or model-based valuation techniques

may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2017, 2016 and 2015, except for the transfer out of Level 3 noted below, there were no significant transfers in or out of Levels 1, 2, or 3.

Transfer of Gas Basin Specific Contracts and Gas Basis Contracts: During 2016 the Company determined that its gas basin specific contracts and gas basis contracts met the requirements to be categorized as a Level 2 fair value. The transfer of these assets out of Level 3 was primarily the result of increased price observability of the inputs used in assessing the assets’ fair value throughout the full term of the derivatives.

The tables below set forth quantitative information about Energen’s Level 3 fair value measurements of derivative commodity instruments as follows:



(in thousands, except price data)	Fair Value as of December 31, 2017			Valuation Technique*	Unobservable Input*	Range
Oil Basis - WTI/WTI
2018	$	(11,374	)	Discounted Cash Flow	Forward Basis	($0.03) - $0.11 Bbl
2019	$	(626	)	Discounted Cash Flow	Forward Basis	($0.36) - ($0.24) Bbl
Natural Gas Liquids
2018	$	(16,764	)	Discounted Cash Flow	Forward Basis	$0.74 - $0.78 Gal
2019	(524		)	Discounted Cash Flow	Forward Basis	$0.68 Gal

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in Energen’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values of these assets and liabilities.

Asset retirement obligations: Energen’s asset retirement obligations (ARO) primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. See Note 13, Asset Retirement Obligations, for further discussion related to these ARO’s. These assumptions are classified as Level 3 fair value measurements.

Asset Impairments: We monitor our oil and natural gas properties as well as the market and business environments in which we operate and make assessments about events that could result in potential impairment. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected field production performance. If a material event occurs, Energen makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, we will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows and values derived from purchase and sale agreements and similar support as applicable. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future.

These assumptions are classified as Level 3 fair value measurements. See Note 14, Asset Impairment, for impairments recognized by Energen during the years ended December 31, 2017, 2016 and 2015.

Financial Instruments Not Carried at Fair Value

The stated value of cash and cash equivalents, short-term investments, accounts receivables (net of allowance for doubtful accounts), and short-term debt approximates fair value due to the short maturity of the instruments. Short-term investments purchased and sold during 2015 of $919 million are not considered readily convertible into cash and accordingly are not classified in cash and cash equivalents. In addition, the Company also invested in certain short-term investments that qualify and were classified as cash and cash equivalents. The fair value of Energen’s long-term debt, including the current portion and notes payable to banks, approximates $798.9 million and $559.9 million and has a carrying value of $785.0 million and $554.0 million at December 31, 2017 and 2016, respectively. The fair values are based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value measurements.

Concentration of Credit Risk

Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil, natural gas liquids and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect Energen’s overall exposure to credit risk, either positively or negatively, in that our oil, natural gas liquids and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest purchasers of Energen’s oil, natural gas liquids and natural gas, Plains Marketing, LP (Plains) and Shell Trading (US) Company (Shell), accounted for approximately 50 percent and 18 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2017 . Energen’s other purchasers each accounted for less than 7 percent of these accounts receivable as of December 31, 2017 . During the year ended December 31, 2017 , Plains and Shell accounted for approximately 56 percent and 13 percent , respectively, of total revenues from oil, natural gas liquids and natural gas sales. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2017 .

9. EXPLORATORY COSTS

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:



Years ended December 31, (in thousands)	2017			2016			2015
Capitalized exploratory well costs at beginning of period	$	164,996		$	103,588		$	119,439
Additions pending determination of proved reserves	666,282			344,045			634,908
Reclassifications due to determination of proved reserves	(699,078		)	(282,637		)	(650,759		)
Capitalized exploratory well costs at end of period	$	132,200		$	164,996		$	103,588

The following table sets forth capitalized exploratory wells costs:



(in thousands)	December 31, 2017		December 31, 2016
Exploratory wells in progress (drilling rig not released)	$	10,879	$	14,531
Capitalized exploratory well costs for a period of one year or less	121,321		143,602
Capitalized exploratory well costs for a period greater than one year	—		6,863
Total capitalized exploratory well costs	$	132,200	$	164,996

At December 31, 2017, Energen had 49 gross exploratory wells either drilling or waiting on results from completion and testing in the Permian Basin. No wells were capitalized for a period greater than one year as of December 31, 2017.

10. RECONCILIATION OF EARNINGS PER SHARE



Years ended December 31,
(in thousands, except per share amounts)			2017						2016							2015
	Net Income		Shares	Per Share Amount		Net Loss			Shares	Per Share Amount			Net Loss			Shares	Per Share Amount
Basic EPS	$	306,828	97,182	$	3.16	$	(167,513	)	94,476	$	(1.77	)	$	(945,731	)	76,078	$	(12.43	)
Effect of dilutive securities
Stock options			26						—							—
Non-vested restricted stock			300						—							—
Performance share awards			199						—							—
Diluted EPS	$	306,828	97,707	$	3.14	$	(167,513	)	94,476	$	(1.77	)	$	(945,731	)	76,078	$	(12.43	)

In periods of loss, shares that otherwise would have been included in diluted average commons shares outstanding are excluded. Energen had 330,690 and 355,915 of excluded shares for the years ended December 31, 2016 and 2015, respectively.

Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive.



Years ended December 31, (in thousands)	2017	2016	2015
Stock options	512	539	114
Performance share awards	131	—	—

11. EQUITY OFFERING

During the first quarter of 2016, Energen issued 18,170,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $381.1 million , after deducting offering expenses. Net proceeds from this offering were used to repay borrowings under our credit facility and for general corporate purposes.

During the second quarter of 2015, Energen issued 5,700,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $398.6 million , after deducting offering expenses. Net proceeds from this offering were used to repay borrowings under our credit facility and for general corporate purposes.

12. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Under various agreements for third-party gathering, treatment, transportation or other services, Energen is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 2.9 MMBOE through October 2020 .

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen and Energen Resources. Historically, the cost of environmental compliance has not materially affected our financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and we have accrued a provision for our estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. We recognize a liability for contingencies, including an estimate of legal costs to be incurred, when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

On November 4, 2015, Energen Resources filed a quiet title action against Endeavor Energy Resources, L.P. (Endeavor) in the District Court of Howard County, Texas, to remove a cloud on the title to approximately 10,000 acres leased by Energen Resources in that county. Energen Resources believes the cloud on title arises from a prior, unreleased but partially terminated oil and gas lease covering the leased lands. The trial judge ruled with respect to the acreage not held by production that Endeavor’s lease terminated prior to the date Energen Resources entered into its lease. In November 2016, the trial judge entered a final judgment to that effect and that judgment has been appealed by Endeavor.

On October 24, 2017, Energen reached an agreement to settle a lawsuit over certain leasehold interests. Energen received 917.2 net mineral acres and recorded a gain of $6.4 million in gain on sale of assets and other, net on the consolidated statements of operations associated with this settlement during 2017.

New Mexico Audits: In 2011, Energen Resources received an Order to Perform Restructured Accounting and Pay Additional Royalties (the Order), following an audit performed by the Taxation and Revenue Department (the Department) of the State of New Mexico on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Order addressed ONRR’s efforts to change accounting and reporting practices, and to unbundle fees charged by third parties that gather, compress and transport natural gas production. ONRR now maintains that all or some of such fees are not deductible.

Lease Obligations: Energen’s total lease payments included as operating lease expense were $20.8 million , $22.6 million and $23.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Minimum future rental payments required after 2017 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:



Years Ending December 31, (in thousands)
2018	2019	2020	2021	2022	2023 and thereafter
$4,648	$3,243	$605	$—	$—	$—

13. ASSET RETIREMENT OBLIGATIONS

Energen’s asset retirement obligations primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. The ARO fair value liability is determined by calculating the present value of the estimated future cash outflows, adjusted for inflation, we expect to incur to plug, abandon and reclaim our producing properties at the end of their productive lives, and is recognized on a discounted basis incorporating an estimate of performance risk specific to Energen. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful lives of the related assets. Upon settlement of the liability, Energen may recognize a gain or loss for differences between estimated and actual settlement costs.

The following table reflects the components of the change in Energen’s ARO balance:



(in thousands)
Balance as of December 31, 2014	$	94,060
Liabilities incurred	981
Liabilities settled	(686		)
Accretion expense	7,108
Reclassification associated with held for sale properties*	(11,473		)
Balance as of December 31, 2015	89,990
Liabilities incurred	230
Liabilities settled	(758		)
Accretion expense	6,672
Revisions in estimated cash flows	(12,875		)
Reclassification associated with held for sale properties**	(1,715		)
Balance as of December 31, 2016	81,544
Liabilities incurred	1,354
Liabilities settled	(351		)
Accretion expense	5,831
Balance as of December 31, 2017	$	88,378

*Asset retirement obligation associated with certain San Juan Basin properties related to assets held for sale.

**Adjustment to the reclassification of the asset retirement obligation associated with a series of asset sales of certain non-core Permian Basin Assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico.

14. ASSET IMPAIRMENT

Impairments recognized by Energen are presented below:



Years ended December 31, (in thousands)	2017		2016		2015
Permian Basin properties
Central Basin Platform	$	1,096	$	187,043	$	484,848
Delaware Basin	—		21,288		607,303
Midland Basin	—		—		—
San Juan Basin properties	—		7,519		133,055
Permian Basin unproved leasehold properties	575		4,762		29,168
San Juan Basin unproved leasehold properties	—		40		37,934
Total asset impairments	$	1,671	$	220,652	$	1,292,308

Non-cash impairment writedowns are reflected in asset impairment in the consolidated statements of operations.

Permian Basin: During 2017, Energen recognized non-cash impairment writedowns in the Permian Basin of $1.1 million to adjust the carrying amount of these proved properties to their fair value.

Energen recognized non-cash impairment writedowns on properties in the San Juan Basin of $133.1 million during 2015 to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. During 2015, Energen recognized unproved leasehold writedowns on San Juan Basin properties of $37.9 million .

15. ACQUISITION AND DISPOSITION OF PROPERTIES

During 2017, Energen completed a total of $273.3 million in various purchases and renewals of unproved acquisitions, which are accounted for as asset acquisitions, including approximately $217.4 million in the Delaware Basin and approximately $36.9 million in the Midland Basin for unproved leasehold and $19.0 million for mineral purchases primarily in the Delaware Basin. Energen completed an estimated $143.7 million in various purchases and renewals of unproved leasehold largely in the Permian Basin, including approximately $77 million of acreage purchased in Lea County, New Mexico, during 2016. Energen completed an estimated total of $85.7 million in various purchases of unproved leasehold largely in the Permian Basin during 2015.

During 2016, Energen completed a series of asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico for an aggregate purchase price of $552 million . These transactions had closing dates of June 3, June 7, June 30, July 15 and August 9 of 2016 with various effective dates ranging from March 1, 2016 to June 30, 2016. Minor portions of the assets were transferred to other parties upon the exercise of preferential purchase rights under pre-existing joint operating agreements in the ordinary course of business. Pre-tax proceeds to Energen were approximately $532.2 million after purchase price adjustments of approximately $19 million related to the operations of the properties subsequent to the effective dates and other one-time adjustments including transfer payments and certain amounts due to the buyer, but before consideration of transaction costs of approximately $5 million . Energen recognized pre-tax post-closing adjustment losses of $0.6 million in 2017 and pre-tax gains of $246.3 million in 2016 on the sales. Energen used the proceeds from the sale to fund ongoing operations.

On March 31, 2015, Energen completed the sale of the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado (effective as of January 1, 2015) for an aggregate purchase price of $395 million . The sales proceeds were reduced by purchase price adjustments of approximately $11 million related to the operations of the San Juan Basin properties subsequent to December 31, 2014 and one-time adjustments related primarily to liabilities assumed by the buyer, which resulted in pre-tax proceeds to Energen of approximately $384 million before consideration of transaction costs of approximately $2.8 million . Energen recognized a pre-tax gain of $27.0 million on the sale. Energen used the proceeds from the sale to reduce long-term indebtedness. At December 31, 2014, proved reserves associated with these San Juan Basin properties totaled 69,038 MBOE.

16. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning Energen’s cash flow activities from operations was as follows:



Years ended December 31, (in thousands)	2017		2016		2015
Interest paid, net of amount capitalized	$	34,970	$	35,919	$	40,747
Income taxes paid	$	2,193	$	562	$	8,114
Noncash investing activities:
Accrued development, exploration costs and other capital	$	74,909	$	79,988	$	79,206
Capitalized asset retirement obligations costs	$	1,354	$	230	$	981
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	9,536	$	6,675	$	5,758
Treasury stock acquired in connection with tax withholdings	$	3,293	$	2,610	$	4,722

17. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects:



(in thousands)
Balance as of December 31, 2016	$	1,405
Other comprehensive income before reclassifications	(693		)
Amounts reclassified from accumulated other comprehensive income (loss)	(332		)
Change in accumulated other comprehensive income (loss)	(1,025		)
Balance as of December 31, 2017	$	380

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss):



Years ended December 31, (in thousands)	2017			2016			2015
	Amounts Reclassified									Line Item Where Presented
Pension and postretirement plans:
Prior service cost	$	454		$	465		$	—		General and administrative
Actuarial losses	(10		)	(3,058		)	(30,504		)	General and administrative
Total pension and postretirement plans	444			(2,593		)	(30,504		)
Income tax (expense) benefit*	(112		)	992			10,676
Net of tax	332			(1,601		)	(19,828		)
Total reclassifications for the period	$	332		$	(1,601	)	$	(19,828	)

*In 2017, revisions associated with the Tax Cuts and Jobs Act were reflected in the income tax (expense) benefit line item above.

18. RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2017, the Financial Accounting Standards Board (FASB) issued ASU No. 2017-09, Stock Compensation - Scope of Modification Accounting. The amendments in this update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The amendment is effective for annual periods beginning after December 15, 2017, and interim periods within those annual years. This amendment is not expected to have a material impact to the Company’s financial position or results of operations.

In March 2017, the FASB issued ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments in this update require that the service cost component of net periodic postretirement benefit expense be presented in the same statement of operations line item as other employee compensation costs, while the remaining components of net periodic postretirement benefit expense are to be presented outside operating income. The amendment is effective for annual periods beginning after December 15, 2017, and interim periods within those annual years. This amendment is not expected to have a material impact to the Company’s financial position or results of operations.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update will be applied using the retrospective transition method. Adoption of this standard will only affect the presentation of the Company’s cash flows and is not expected to have a material impact on the Company’s consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which makes a number of changes meant to simplify and improve accounting for share-based payments. The amendment was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The adoption of this ASU effective January 1, 2017 did not have a material impact on our consolidated financial statements. Upon adoption of this new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in our consolidated statements of operations as a discrete item in the reporting period in which they occur. The presentation requirements for cash flows related to employee taxes paid for withheld shares were adjusted retrospectively. These cash outflows, which were historically presented as an operating activity, were classified as a financing activity under taxes paid for shares withheld on the consolidated statements of cash flows. The Company also had an approximate $170,000 decrease to retained earnings associated with our election to recognize forfeitures as they occur.

In February 2016, the FASB issued ASU No. 2016-02, Leases. This update increases transparency and comparability by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The primary effect of adopting the new standard will be to record assets and obligations on the balance sheet for contracts currently recognized as operating leases. We have identified certain applicable leases under the standard and are currently developing an inventory of all applicable leases, however, this standard is not applicable to oil and natural gas leases. The Company is still evaluating the impact of this standard on our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This update is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. Companies may apply this update retrospectively or using a modified retrospective approach to adjust retained earnings. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers, which deferred the effective date of ASU No. 2014-09 to annual periods beginning after December 15, 2017, including interim reporting periods within that reporting period. The Company will adopt this standard using the modified retrospective method of adoption on January 1, 2018. We have evaluated the impact of this standard on our individual customer contracts and do not expect a significant impact to our consolidated financial statements.

19. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

The following data summarizes quarterly operating results:



	Year ended December 31, 2017
(in thousands, except per share amounts)	First		Second		Third			Fourth
Revenues	$	240,921	$	256,824	$	191,504		$	271,796
Operating income (loss)	$	61,427	$	54,714	$	(17,822	)	$	46,817
Net income (loss)	$	33,403	$	29,481	$	(18,486	)	$	262,430
Diluted earnings per average common share	$	0.34	$	0.30	$	(0.19	)	$	2.68
Basic earnings per average common share	$	0.34	$	0.30	$	(0.19	)	$	2.70



	Year ended December 31, 2016
(in thousands, except per share amounts)	First			Second		Third		Fourth
Revenues	$	128,219		$	105,765	$	184,385	$	114,520
Operating income (loss)	$	(301,811	)	$	68,875	$	90,302	$	(68,596	)
Net income (loss)	$	(203,116	)	$	36,759	$	53,314	$	(54,470	)
Diluted earnings per average common share	$	(2.34	)	$	0.38	$	0.55	$	(0.56	)
Basic earnings per average common share	$	(2.34	)	$	0.38	$	0.55	$	(0.56	)

20. OIL AND NATURAL GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:



(in thousands)	December 31, 2017		December 31, 2016
Proved	$	8,466,708	$	7,543,464
Unproved	453,028		196,888
Total capitalized costs	8,919,736		7,740,352
Accumulated depreciation, depletion and amortization	4,200,797		3,723,669
Capitalized costs, net	$	4,718,939	$	4,016,683

Costs Incurred: The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:



Years ended December 31, (in thousands)	2017		2016		2015
Property acquisition:
Proved*	$	9,889	$	4,066	$	1,866
Unproved	273,326		143,667		85,690
Exploration	676,357		349,463		649,764
Development	235,279		89,624		372,177
Total costs incurred	$	1,194,851	$	586,820	$	1,109,497

* Includes a $6.4 million noncash lawsuit settlement over certain leasehold interests.

Results of Operations From Producing Activities: The following table sets forth results of Energen’s oil, natural gas liquids and natural gas operations from producing activities:



Years ended December 31, (in thousands)	2017		2016			2015
Gross revenues*	$	961,045	$	532,889		$	878,554
Production (lifting costs)	243,144		214,652			285,760
Exploration expense	10,075		5,415			14,877
Depreciation, depletion and amortization including asset impairments	480,491		663,659			1,880,190
Accretion expense	5,831		6,672			7,108
Income tax expense (benefit)**	79,815		(123,153		)	(469,362		)
Results of operations from producing activities	$	141,689	$	(234,356	)	$	(840,019	)

* The years ended December 31, 2017, 2016 and 2015 gross revenues include pre-tax non-cash mark-to-market losses on derivatives of $10.8 million , $71.2 million and $281.8 million , respectively.

**Income tax benefit does not reflect any impact due to the enactment of the Tax Cuts and Jobs Act in 2017.

Oil and Natural Gas Reserves: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Proved reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2017 , 2016 and 2015 . Changes to prices and costs could have a significant effect on the disclosed amount of proved reserves and their associated values. In addition, the estimation of proved reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of proved reserves disclosed. The Company’s proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and natural gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott), independent oil and natural gas reservoir engineers, have audited the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen has attributed to its net interests in oil and natural gas properties as of December 31, 2017 . Ryder Scott audited the proved reserve estimates for substantially all of the Permian Basin proved reserves. The independent reservoir engineers have issued reports covering approximately 99 percent of Energen’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.



Year ended December 31, 2017	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	199,575		58,046		352,248		316.3
Revisions of previous estimates	7,903		14,853		102,107		39.8
Purchases	179		37		201		0.2
Extensions and discoveries	66,304		23,098		156,461		115.5
Production	(16,951	)	(5,255	)	(33,528	)	(27.8	)
Proved reserves at end of period	257,010		90,779		577,489		444.0
Proved developed reserves at end of period	143,907		52,882		342,616		253.9
Proved undeveloped reserves at end of period	113,103		37,897		234,873		190.1



Year ended December 31, 2016	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	210,691		71,713		433,904		354.7
Revisions of previous estimates	(17,840	)	(6,800	)	(7,779	)	(26.0	)
Purchases	103		21		89		0.1
Extensions and discoveries	45,129		10,480		50,780		64.1
Production	(13,213	)	(3,892	)	(27,204	)	(21.6	)
Sales	(25,295	)	(13,476	)	(97,542	)	(55.0	)
Proved reserves at end of period	199,575		58,046		352,248		316.3
Proved developed reserves at end of period	101,202		29,767		187,117		162.1
Proved undeveloped reserves at end of period	98,373		28,279		165,131		154.2



Year ended December 31, 2015	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	181,227		73,463		707,926		372.7
Revisions of previous estimates	(39,537	)	(11,979	)	(44,176	)	(58.9	)
Purchases	2		1		2		0.0
Extensions and discoveries	83,319		25,530		143,022		132.6
Production	(14,023	)	(4,065	)	(35,604	)	(24.0	)
Sales	(297	)	(11,237	)	(337,266	)	(67.7	)
Proved reserves at end of period	210,691		71,713		433,904		354.7
Proved developed reserves at end of period	108,319		36,374		236,112		184.0
Proved undeveloped reserves at end of period	102,372		35,339		197,792		170.7

2017 Activities: Energen had net upward reserve revisions during 2017 which totaled 39.8 MMBOE and include upward revisions of approximately 11.6 MMBOE related to changes in year-end pricing, 17.6 MMBOE related to extending lateral length of certain locations, 12.0 MMBOE due to improved well performance and 3.0 MMBOE due to changes in plant yield. These were partially offset by net downward reserve revisions of 4.6 MMBOE of proved undeveloped reserves that will no longer be developed in the five-year time horizon.

Energen purchased 0.2 MMBOE of reserves during 2017 primarily related to the acquisition of oil properties in the Permian Basin.

During 2017, Energen had extensions and discoveries of 115.5 MMBOE of which 27 percent were proved undeveloped reserves and 73 percent were proved developed reserves. Extension drilling resulted in 0.6 MMBOE of discoveries with exploratory drilling providing 114.9 MMBOE of discoveries.

2016 Activities: Energen had net downward reserve revisions during 2016 which totaled 26.0 MMBOE including approximately 10.6 MMBOE related to changes in year-end pricing and downward revisions of approximately 22.9 MMBOE of proved undeveloped reserves that will no longer be developed in the five-year time horizon due to development being delayed to focus on other assets with higher returns. Net upward reserve revisions of 7.5 MMBOE due to factors other than price included increased lateral length, lower lease operating expense and improved well performance partially offset by changes in plant yields.

Energen purchased 0.1 MMBOE of reserves during 2016 primarily related to the acquisition of oil properties in the Permian Basin.

During 2016, Energen had extensions and discoveries of 64.1 MMBOE of which 65 percent were proved undeveloped reserves and 35 percent were proved developed reserves. Extension drilling resulted in no discoveries with exploratory drilling providing 64.1 MMBOE of discoveries.

During 2016, Energen had sales of 55.0 MMBOE primarily due to the sale of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico.

2015 Activities: Energen had net downward reserve revisions during 2015 which totaled 58.9 MMBOE including negative revisions of approximately 38.0 MMBOE related to changes in year-end pricing and negative revisions of approximately 8.2 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period. Other negative revisions were 5.5 MMBOE due to increased declines in certain Wolfberry wells and 5.0 MMBOE of Wolfcamp reserves due to interference caused by our wellbore placement geometry.

During 2015, Energen had extensions and discoveries of 132.6 MMBOE, primarily in the Permian Basin, of which 78 percent were proved undeveloped reserves and 22 percent were proved developed reserves. Extension drilling resulted in 3.1 MMBOE of discoveries with exploratory drilling providing 129.5 MMBOE of discoveries.

During 2015, Energen had sales of 67.7 MMBOE primarily due to the sale of certain natural gas assets in the San Juan Basin.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of Energen’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Open mark-to-market derivatives applicable to future periods are excluded from the calculation of standardized measure of future net cash flows.



Years ended December 31, (in thousands)	2017		2016		2015
Future gross revenues	$	15,531,237	$	9,191,808	$	11,714,729
Future production costs	4,467,989		3,126,153		4,353,974
Future development costs	2,077,918		1,632,577		1,961,661
Future income tax expense	1,381,999		762,921		1,065,887
Future net cash flows	7,603,331		3,670,157		4,333,207
Discount at 10% per annum	4,283,536		2,320,350		2,299,859
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	3,319,795	$	1,349,807	$	2,033,348

The following are the principal sources of changes in the standardized measure of discounted future net cash flows:



Years ended December 31, (in thousands)	2017			2016			2015
Balance at beginning of year	$	1,349,807		$	2,033,348		$	4,219,656
Revisions to reserves proved in prior years:
Net changes in prices and production costs	659,802			(343,839		)	(3,101,283		)
Net changes in future development costs	(86,642		)	122,200			239,692
Net changes due to revisions in quantity estimates	389,684			(167,188		)	(404,708		)
Development costs incurred, previously estimated	148,534			71,099			350,560
Accretion of discount	149,664			203,335			542,105
Changes in timing and other*	257,523			(100,742		)	(1,024,114		)
Total revisions	1,518,565			(215,135		)	(3,397,748		)
New field discoveries and extensions, net of future production and development costs	1,492,562			352,358			776,315
Sales of oil and gas produced, net of production costs	(788,130		)	(440,446		)	(514,380		)
Purchases	3,769			1,733			8
Sales	—			(235,222		)	(372,039		)
Net change in income taxes	(256,778		)	(146,829		)	1,321,536
Net change in standardized measure of discounted future net cash flows	1,969,988			(683,541		)	(2,186,308		)
Balance at end of year	$	3,319,795		$	1,349,807		$	2,033,348

*Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program.


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

a. Disclosure Controls and Procedures

Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

b. Management’s Report on Internal Control Over Financial Reporting

Management 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. Energen Corporation’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 accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written 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 Energen Corporation;


ii	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Energen Corporation are being made only in accordance with authorization of management and directors of Energen Corporation; and


iii	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

Management assessed the effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2017 . Management based this assessment on criteria for effective internal control over financial reporting described in “ Internal Control - Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Energen Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management determined that, as of December 31, 2017 , Energen Corporation maintained effective internal control over financial reporting. The effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2017 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

c. Changes in Internal Control Over Financial Reporting

Our chief executive officer and chief financial officer have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen’s definitive proxy statement for its 2018 Annual Meeting of Shareholders

ITEM 11. EXECUTIVE COMPENSATION

The information regarding executive compensation is incorporated herein by reference from Energen’s definitive proxy statement for its 2018 Annual Meeting of Shareholders.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

a. Security Ownership of Certain Beneficial Owners

The information regarding the security ownership of the beneficial owners of more than five percent of Energen’s common stock is incorporated herein by reference from Energen’s definitive proxy statement for its 2018 Annual Meeting of Shareholders.

b. Security Ownership of Management

The information regarding the security ownership of management is incorporated herein by reference from Energen’s definitive proxy statement for its 2018 Annual Meeting of Shareholders.

c. Securities Authorized for Issuance Under Equity Compensation Plans

The following table summarizes information concerning securities authorized for issuance under equity compensation plans as of December 31, 2017:



Plan Category	Number of Securities to be Issued for Outstanding Options, Performance Share Awards and Restricted Stock Units	Weighted Average Exercise Price		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders*	1,883,175	$	53.25	2,089,649
Equity compensation plans not approved by security holders	—	—		—
Total	1,883,175	$	53.25	2,089,649

*These plans include 1,444,057 shares associated with Energen’s Stock Incentive Plan, 76,904 shares associated with the 1992 Energen Corporation Directors Stock Plan and 568,688 shares associated with the 1997 Deferred Compensation Plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information regarding certain relationships and related transactions, and director independence is incorporated herein by reference from Energen’s definitive proxy statement for its 2018 Annual Meeting of Shareholders.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen’s definitive proxy statement for its 2018 Annual Meeting of Shareholders.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a. Documents Filed as Part of This Report


(1)	Financial Statements

The consolidated financial statements of Energen are included in Item 8 of this Form 10-K.

(2) Financial Statement Schedules

No financial statement schedules are required to be filed as part of this Form 10-K or they are inapplicable.

(3) Exhibits

The exhibits listed on the accompanying Index to Exhibits are filed as part of this Form 10-K.

ITEM 16. FORM 10-K SUMMARY

None

Energen Corporation

INDEX TO EXHIBITS

Item 14(a)(3)



Exhibit
Number	Description

*3(a)	Restated Certificate of Incorporation of Energen Corporation (composite, as amended April 29, 2005) which was filed as Exhibit 3(a) to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005

*3(b)	Articles of Amendment to Restated Certificate of Incorporation of Energen, designating Series 1998 Junior Participating Preferred Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energen’s Post Effective Amendment No. 1, filed on August 7, 1998, to Registration Statement on Form S-3 (Registration No. 333-00395)

*3(c)	Bylaws of Energen Corporation (as amended through December 4, 2017) which was filed as Exhibit 3.1 to Energen’s Current Report on Form 8-K, dated December 7, 2017

*4(a)	Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September 1, 1996 (the “Energen 1996 Indenture”), and which was filed as Exhibit 4(i) to the Registrant’s Registration Statement on Form S-3 (Registration No. 333-11239) filed August 30, 1996

*4(a)(i)	Officers’ Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001

*4(a)(ii)	Officers’ Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001

*4(a)(iii)	Amended and Restated Officers’ Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filed as Exhibit 4(d)(iii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001

*4(a)(iv)	Officers’ Certificate, dated August 5, 2011, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 4.65 percent Senior Notes due September 1, 2021, which was filed as Exhibit 4.1 to Energen’s Current Report on Form 8-K, dated August 5, 2011

*10(a)	Credit Agreement dated September 2, 2014, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed September 2, 2014

*10(b)	First Amendment to the Credit Agreement dated as of October 20, 2014, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed October 23, 2014

*10(b)(i)	Second Amendment to the Credit Agreement dated as of April 16, 2015, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed April 20, 2015

*10(b)(ii)	Third Amendment to the Credit Agreement dated as of October 20, 2015, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed October 23, 2015

*10(b)(iii)	Fourth Amendment to the Credit Agreement dated as of April 13, 2016, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed April 14, 2016



*10(b)(iv)	Fifth Amendment to the Credit Agreement dated as of October 25, 2016, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed October 26, 2016

*10(b)(v)	Sixth Amendment to the Credit Agreement dated as of April 21, 2017, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed April 25, 2017

*10(b)(vi)	Seventh Amendment to the Credit Agreement dated as of November 9, 2017, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed November 14, 2017

*10(c)	Commitment Increase Letter dated November 17, 2014, by and among Energen Corporations, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed November 18, 2014

*10(d)	Form of Severance Compensation Agreement (Change in Control) between Energen Corporation and its executive officers which was filed as Exhibit 10(d) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2016

*10(e)	Form of Executive Severance Agreement between Energen Corporation and its named executive officers which was filed as Exhibit 10(a) to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017.

*10(f)	Energen Corporation Stock Incentive Plan (as amended effective November 7, 2017) which was filed as Exhibit 10(b) to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017)

*10(g)	Form of Stock Option Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(r) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012

*10(h)	Form of Restricted Stock Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(s) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012

*10(i)	Form of Restricted Stock Unit Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed December 12, 2013

*10(j)	Form of Performance Share Award under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(t) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012

*10(k)	Energen Corporation Annual Incentive Compensation Plan, as amended effective January 1, 2016, which was filed as Exhibit 10 to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016

*10(l)	Energen Corporation 1997 Deferred Compensation Plan (as amended and restated) effective October 22, 2014, which was filed as Exhibit 10(m) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2014

*10(m)	Energen Corporation Directors Stock Plan (as amended April 28, 2010) which was filed as an attachment to Energen’s definitive Proxy Statement on Schedule 14A , filed March 19, 2010

21	Subsidiaries of Energen Corporation

23(a)	Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)

23(b)	Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company, L.P. )



24	Power of Attorney

31(a)	Energen Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)

31(b)	Energen Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)

32	Energen Corporation Certification pursuant to 18 U.S.C. Section 1350

99(a)	Reserve Audit – Ryder Scott & Company, L.P.

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

*Incorporated by reference

SIGNATURE

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.

ENERGEN CORPORATION

(Registrant)



February 28, 2018	By	/s/ J.T. McManus, II
	J.T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation;

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



February 28, 2018	By	/s/ J.T. McManus, II
	J.T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation

February 28, 2018	By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

February 28, 2018	By	/s/ Russell E. Lynch, Jr.
	Russell E. Lynch, Jr. Vice President and Controller of Energen Corporation

February 28, 2018	*
	Kenneth W. Dewey Director

February 28, 2018	*
	Laurence M. Downes Director

February 28, 2018	*
	M. James Gorrie Director

February 28, 2018	*
	Jay Grinney Director

February 28, 2018	*
	William G. Hargett Director

February 28, 2018	*
	Frances Powell Hawes Director

February 28, 2018	*
	Alan A. Kleier Director

February 28, 2018	*
	Lori A. Lancaster Director

	*By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Attorney-in-Fact

Exhibit 21

SUBSIDIARIES OF ENERGEN CORPORATION

Energen Resources Corporation*

* Incorporated in the State of Alabama

Exhibit 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-203914) and Forms S-8 (No. 333-212331, No. 33-48505, No. 333-59804, No. 333-26111, No. 333-45107, No. 333-84170 and No. 333-178794) of Energen Corporation of our report dated February 28, 2018 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 28, 2018

Exhibit 23(b)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen Corporation attributed to its net interests in oil and natural gas properties located in the U.S. as of December 31, 2017 which appears in this Form 10-K and the inclusion of our report dated February 14, 2018, which appears as an Exhibit to this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-203914) and Forms S-8 (No. 333-212331, No. 33-48505, No. 333-59804, No. 333-26111, No. 333-45107, No. 333-84170 and No. 333-178794) of Energen Corporation to the reference to our firm name and our audit of the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen Corporation attributed to its net interests in oil and natural gas properties located in the U.S. as of December 31, 2017 which appears in this Form 10-K and our report dated February 14, 2018, which appears as an Exhibit to this Form 10-K.

/s/ Ryder Scott Company, L.P.

Houston, Texas

February 28, 2018

Exhibit 24

POWER OF ATTORNEY

ENERGEN CORPORATION

Each of the undersigned directors of Energen Corporation, an Alabama corporation, hereby nominates, constitutes and appoints James T. McManus, II, and Charles W. Porter, Jr., and each of them, the true and lawful attorneys of the undersigned to sign the name of the undersigned as director to the Annual Reports on Form 10-K for the year ended December 31, 2017 , of said corporation to be filed with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, and to any and all amendments to said report.

Each of the undersigned hereby grants to said attorneys full power of substitution, resubstitution and revocation, all as fully as the undersigned could do if personally present, hereby ratifying all that said attorneys or their substitutes may lawfully do by virtue hereof.

IN WITNESS WHEREOF, each of the undersigned directors of Energen Corporation have executed this Power of Attorney as of the 7 ^th day of February, 2018.



/s/ Kenneth W. Dewey		/s/ William G. Hargett
Kenneth W. Dewey		William G. Hargett

/s/ Laurence M. Downes		/s/ Frances Powell Hawes
Laurence M. Downes		Frances Powell Hawes

/s/ M. James Gorrie		/s/ Alan A. Kleier
M. James Gorrie		Alan A. Kleier

/s/ Jay Grinney		/s/ Lori A. Lancaster
Jay Grinney		Lori A. Lancaster

Exhibit 31(a)

CERTIFICATION

I, James T. McManus, II, certify that:


1.	I have reviewed this report on Form 10-K of Energen Corporation;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



February 28, 2018	By	/s/ J. T. McManus, II
		J. T. McManus, II Chairman and Chief Executive Officer of Energen Corporation

Exhibit 31(b)

CERTIFICATION

I, Charles W. Porter, Jr., certify that:


1.	I have reviewed this report on Form 10-K of Energen Corporation;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



February 28, 2018	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Energen Corporation (the “Registrant”) on Form 10-K for the period ended December 31, 2017 , as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the Registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Dated as of February 28, 2018



By	/s/ J. T. McManus, II
	J. T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation

By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Energen Corporation and will be retained by Energen Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 99(a)

ENERGEN RESOURCES CORPORATION

Proved Reserves Audit

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2017

\s\ Joseph E. Blankenship

Joseph E. Blankenship, P.E.

TBPE License No. 62093

Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849

1100 LOUISIANA STREET SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191

February 14, 2018

Energen Resources Corporation

605 Richard Arrington, Jr. Boulevard North

Birmingham, AL 35203-2707

Attention: Mr. Mike Allison, Engineering Manager

Gentlemen:

At the request of Energen Resources Corporation (Energen), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2017 prepared by Energen’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on February 13, 2018 and presented herein, was prepared for public disclosure by Energen in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Energen’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by Energen and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2017. The properties reviewed by Ryder Scott incorporate 3,484 reserve determinations and are located in the states of New Mexico and Texas.

The properties reviewed by Ryder Scott account for a portion of Energen’s total net proved reserves as of December 31, 2017. Based on the estimates of total net proved reserves prepared by Energen, the reserves audit conducted by Ryder Scott addresses the percentages shown below.

Percent of Energen’s Total Net Proved Reserves

Audited by Ryder Scott



Reserve Class and Category	Percent of Liquid Hydrocarbons	Percent of Gas	Percent of Oil Equivalent

Total Proved	99.6	98.5	99.3
Proved Developed	99.2	97.5	98.9
Proved Undeveloped	100.0	100.0	100.0

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790

621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258

The estimated reserves presented in this report are related to hydrocarbon prices. Energen has informed us that in the preparation of their reserve and income projections, as of December 31, 2017, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Energen attributable to Energen's interest in properties that we reviewed and for those that we did not review are summarized below:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests of

Energen Resources Corporation

As of December 31, 2017



	Proved
	Developed			Total
	Producing	Non-Producing	Undeveloped	Proved
Net Reserves - Audited by Ryder Scott
Oil/Condensate - MBBL	143,095	81	113,103	256,279
Plant Products - MBBL	52,089	45	37,897	90,031
Gas - MMCF	333,844	283	234,872	568,999
Total Equivalent Oil - MBOE	250,825	173	190,145	441,143

Net Reserves - Not Audited by Ryder Scott
Oil/Condensate - MBBL	732	—	—	732
Plant Products - MBBL	748	—	—	748
Gas - MMCF	8,490	—	—	8,490
Total Equivalent Oil - MBOE	2,895	—	—	2,895

Net Reserves - Total Corporation
Oil/Condensate - MBBL	143,827	81	113,103	257,011
Plant Products - MBBL	52,837	45	37,897	90,779
Gas - MMCF	342,333	283	234,872	577,489
Total Equivalent Oil - MBOE	253,720	173	190,145	444,038

Liquid hydrocarbons are expressed in thousand standard 42 gallon barrels (MBBL). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves referred to herein consist of the shut-in and behind pipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Energen’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward”. The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves, prepared by Energen, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through October 2017, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Energen or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 5 percent of the proved producing reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 100 percent of the proved undeveloped reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Energen for our review or which we have obtained from public data sources that were available through October 2017. The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.

Energen’s reserves included in this audit were in conventional and unconventional formations in the Permian Basin. Some of Energen’s properties in the Permian Basin are producing under secondary and enhanced recovery techniques. Many of Energen’s reserves will be produced through horizontal wellbores. Examples would include many of their wells in the Wolfcamp Formation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

To estimate economically recoverable proved oil and gas reserves many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Energen relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Energen for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2017 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Energen for the geographic area reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by Energen to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering fees, transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used by Energen were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Energen.

The table below summarizes Energen’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Energen’s “average realized prices.” The average realized prices shown in the table below were determined from Energen’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Energen’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$51.34/Bbl	$48.39/Bbl
	NGLs	WTI Cushing	$51.34/Bbl	$19.61/Bbl
	Gas	Henry Hub	$2.98/MMBTU	$2.27/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Energen’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by Energen are based on the operating expense reports of Energen and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by Energen were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Energen. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Energen are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Energen were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Energen. The estimated net cost of abandonment after salvage was included by Energen for properties where abandonment costs net of salvage were significant. Energen’s estimates of the net abandonment costs were accepted without independent verification.

The proved undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Energen’s plans to develop these reserves as of December 31, 2017. The implementation of Energen’s development plans as presented to us is subject to the approval process adopted by Energen’s management. As the result of our inquiries during the course of our review, Energen has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Energen’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Energen. Additionally, Energen has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2017, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. All of Energen’s proved undeveloped reserves are scheduled to be developed within five years from the initial disclosure in an SEC filing.

Current costs used by Energen were held constant throughout the life of the properties.

Energen’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend had been established, future production rates were

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

held constant, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend had been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Energen to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Energen. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Energen’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Energen’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a review of the properties in which Energen owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Energen for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Energen are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Energen has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Energen’s forecast of future proved production, we have relied upon data furnished by Energen with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Energen. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by Energen to be appropriate and sufficient for the purpose of our review of Energen’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Energen and as reviewed by us appropriate for the purpose hereof, and we have used

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Energen, it is our opinion that the overall procedures and methodologies utilized by Energen in preparing their estimates of the proved reserves as of December 31, 2017 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Energen are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by Energen in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with Energen's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Energen's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Energen when its reserve estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Energen.

Other Properties

Other properties, as used herein, are those properties of Energen which we did not review. The proved net reserves attributable to the other properties account for 0.4 percent of the total proved net liquid hydrocarbon reserves and 1.5 percent of the total proved net gas reserves or 0.7 percent of the total proved net reserves on an equivalent barrel, BOE, basis based on estimates prepared by Energen as of December 31, 2017.

The same technical personnel of Energen were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Energen. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Energen.

Energen Resources Corporation is a wholly owned subsidiary of Energen Corporation. Energen Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Energen Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Energen Resources Corporation of the references to our name as well as to the references to our third party report for Energen Corporation, which appears in the December 31, 2017 annual report on Form 10-K of Energen Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Energen Corporation.

We have provided Energen with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Energen and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Joseph E. Blankenship

Joseph E. Blankenship, P.E.

TBPE License No. 62093

Advising Senior Vice President

[SEAL]

JEB (DPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Joseph E. Blankenship was the primary technical person responsible for overseeing the estimation and evaluation process with respect to the preparation of this report.

Mr. Blankenship, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1982, is an Advising Senior Vice President and also serves as Chief Expert for Unconventional Reserves Evaluation. Mr. Blankenship is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Blankenship served in a number of engineering positions with Exxon Company USA. More information regarding Mr. Blankenship’s geographic and job specific experience can be seen on Ryder Scott Company’s website www.ryderscott.com/Company/Employees .

Mr. Blankenship earned a Bachelor of Science degree in Mechanical Engineering from the University of Alabama in 1977. He is a member of the Honorary Engineering Society Pi Tau Sigma and is a licensed Professional Engineer in the State of Texas. While at Exxon, he attended schools on Reservoir Engineering, Well Log Analysis, Economic Evaluation, Oil and Gas Facility Design, and Offshore Platform Design. He is a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE). He has served as Chairman of the SPE Newsletter Committee and has been invited by the SPEE to lecture on Coal Seam Evaluation.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Blankenship fulfills.

Mr. Blankenship’s continuing education in 2017 included classes on Advanced Statistical Analysis, the US Foreign Corrupt Practices Act, Probabilistic Reserves and Resource Evaluation Techniques, and the Reserves Evaluation Program Ogre R3. Mr. Blankenship also served as instructor in courses on Reserves Evaluation in China, and as instructor in a course on Fair Market Value Estimation in Houston, Texas.

Mr. Blankenship’s continuing education in 2016 included classes on Advanced Oil & Gas Well Performance Analysis Techniques, Evaluation of the Marcellus Shale Play, Evaluation of Geologic Seismic Data, and Serving as an Expert Witness in Litigation. Mr. Blankenship also served as instructor in courses on Evaluation of the Barnett Shale Play and How to Schedule Multiple Class Incremental Reserves.

Mr. Blankenship’s continuing education in 2015 included classes on Reservoir Engineering Aspects of Unconventional Reservoirs, SPEE Monograph 4 Decline Curve Analysis Techniques, Petroleum Reservoir Geologic Mapping, Cash Flow Analysis Reporting Software, Seismic Data Evaluation Criteria, Excel Programing Techniques, Cash Flow Analysis Reporting Quality Control, and SEC Comment Letters Review. Mr. Blankenship also served as instructor in two courses on Unconventional and Conventional Reserves Evaluation.

Based on his educational background, professional training and more than 40 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Blankenship has satisfied all of the professional qualifications for both Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

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Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.

Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic

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methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)


(1)	completion intervals which are open at the time of the estimate, but which have not started producing;


(2)	wells which were shut-in for market conditions or pipeline connections; or