10-K 1 egn1231201710k.htm 10-K Document
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
Cautionary Statement Regarding Forward-Looking Statements
 
 
 
 
PART I
 
Item 1.
Business
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
 
 
 
 
PART II
 
 
 
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
 
 
Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and
 
 
Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and
 
 
Financial Disclosure
Item 9A.
Controls and Procedures
 
 
 
 
PART III
 
 
 
 
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and
 
 
Related Stockholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accountant Fees and Services
 
 
 
 
PART IV
 
 
 
 
Item 15.
Exhibits and Financial Statement Schedules
Item 16.
Form 10-K Summary
Signatures
 




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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.
 
 


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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.



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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.


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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.








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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.



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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


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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


9



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.


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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.


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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


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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.


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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.


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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.



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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,


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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


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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


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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.



txnmmapbwa01.jpg



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




19


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


20


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




21


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



22


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.


23



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.



24



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.


egn1231201210kcharta03.jpg


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




25



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




























26



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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


27


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


OVERVIEW OF BUSINESS

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.

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:







28



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).




















29



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



30



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


31



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


32



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.






33



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


34



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.




35



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.



36



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.



37



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


38



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
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.

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.













39



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.

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. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement.

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
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.



40



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.







41



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:

 
Percentage Change in Proved Oil & Natural Gas Reserves From Reported Reserves December 31, 2017
(dollars in thousands)
-5%
-10%
Estimated increase in DD&A expense for 2018, net of tax
$
16,393

$
34,343


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.



42



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.


43



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.

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 swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms.

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



44



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.



45



ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION
INDEX TO FINANCIAL STATEMENTS

 
 
Page
1.
Financial Statements
 
 
 
 
 
Report of Independent Registered Public Accounting Firm
 
 
 
 
Consolidated Balance Sheets as of December 31, 2017 and 2016
 
 
 
 
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015
 
 
 
 
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016
and 2015
 
 
 
 
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2017, 2016
and 2015
 
 
 
 
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015
 
 
 
 
Notes to Financial Statements
 
 
 

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.



46


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.  


47



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