10-K 1 egn1231201510k.htm 10-K 10-K


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, 2015

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
 
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 NO o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES o 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 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. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company 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, 2015: $5,283,012,351

Number of shares outstanding of the registrant’s common stock as of February 5, 2016: 78,791,451 shares

DOCUMENTS INCORPORATED BY REFERENCE
Energen Corporation Proxy Statement to be filed on or about March 21, 2016 (Part III, Item 10-14)



 
ENERGEN CORPORATION
2015 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
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.
 
 
Cash Flow Hedge
The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, natural gas liquids or natural gas production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale.
 
 
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.
 
 
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.
 
 
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.
 
 
Hedging
The use of derivative commodity instruments such as futures, swaps, options and collars to help reduce financial exposure to commodity price volatility.
 
 
Gross Well or Acre
A well or acre in which a working interest is owned.
 
 
LIBOR
London Interbank Offered Rate.
 
 
MBbl
One thousand barrels of oil.
 
 
MBOE
One thousand BOE.
 
 
MBOE/d
One thousand BOE per day.
 
 
Mcf
One thousand cubic feet of natural gas.
 
 
MMBOE
One million BOE.
 
 
MMcf
One million cubic feet of natural gas.
 
 
MMcfe
One million cubic feet of natural gas equivalent.
 
 
MMgal
One million gallons of natural gas liquids.
 
 

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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 gross wells or acres 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.
 
 
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.








4




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 and the San Juan Basin in 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 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

5




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

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

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







6




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 in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Headquartered in Birmingham, Alabama, our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources). At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale.

Prior to September 2, 2014, Energen owned Alabama Gas Corporation (Alagasco), which was engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama. On September 2, 2014, Energen completed the transaction to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion resulting in a pre-tax gain of $726.5 million. This sale had an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. See Note 16, Discontinued Operations and Held for Sale Properties, for further information regarding the sale of Alagasco.

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 Alagasco. Alagasco was formed by merger in 1948. As noted above, Alagasco was sold in 2014 to Laclede.

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 the 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 2015, Energen’s proved reserves totaled 354.7 MMBOE. Substantially all of these proved reserves are located in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Approximately 52 percent of Energen’s year-end proved reserves are proved developed reserves. Energen’s proved reserves are long-lived, with a year-end proved reserves-to-production ratio of 15 years. Oil, natural gas liquids and natural gas represent approximately 59 percent, 20 percent and 21 percent, respectively, of Energen’s proved reserves.

Property Acquisitions and Dispositions: 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 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.


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In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million. Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 that was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013.

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 96 percent of its proved reserves at December 31, 2015.

Energen’s capital spending plans for 2016 target a total investment of approximately $250 million, 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, 2015, Energen’s development and exploratory efforts have added 299 MMBOE of proved reserves from the drilling of 883 gross development, exploratory and service wells (including one sidetrack well) and 154 well recompletions and pay-adds. In 2015, Energen’s successful development and exploratory wells and other activities added approximately 133 MMBOE of proved reserves; Energen drilled 190 gross development, exploratory and service wells (including one sidetrack well), performed some 19 well recompletions and pay-adds, and conducted other operational enhancements. Energen’s production from continuing operations totaled 24 MMBOE in 2015, including 3.8 MMBOE from our held for sale properties. In 2016, production is estimated to range from 19.5 MMBOE to 20.3 MMBOE, with a midpoint of 19.9 MMBOE, including approximately 17.6 MMBOE of estimated production from proved reserves owned at December 31, 2015. Production estimates do not include amounts on held for sale properties or potential future 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,
2015
2014
2013
Development:
 
 
 
Productive
50.8

80.2

169.5

Dry



Total
50.8

80.2

169.5

Exploratory:
 
 
 
Productive
98.5

109.4

89.1

Dry
2.0

1.0

0.9

Total
100.5

110.4

90.0


As of December 31, 2015, Energen was participating in the drilling of 1 gross (1 net) development and 1 gross (1 net) exploratory wells. In addition to the development wells drilled, Energen drilled 12.9, 22.5 and 9.8 net service wells during 2015, 2014 and 2013, respectively. Energen had no service wells in process as of December 31, 2015. Also, as of December 31, 2015, Energen

8




had 48 gross (48 net) drilled but uncompleted wells in the Midland Basin, of which we plan to complete 46 gross (46 net) in 2016.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2015, and developed and undeveloped acreage as of the latest practicable date prior to year end:

 
Gross

Net

Oil wells
5,345

3,513

Gas wells
554

415

Developed acreage
443,139

319,578

Undeveloped acreage
186,054

136,216


There was one well with multiple completions at December 31, 2015. 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 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 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 and natural gas, Plains Marketing, LP (Plains) and Shell Trading (US) Company, accounted for approximately 47 percent and 21 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2015. Energen’s other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2015. During the year ended December 31, 2015, Plains accounted for approximately 33 percent of total revenues, excluding the impact of non-cash mark-to-market open derivatives. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2015.

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. Prior to June 30, 2013, the Company utilized cash flow hedge accounting, where applicable, for its derivative transactions. Effective June 30, 2013, Energen discontinued the use of cash flow hedge accounting and dedesignated all remaining derivative commodity instruments that were previously designated as cash flow hedges.

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 when we successfully pioneered the exploration and development of coalbed methane in Alabama’s Black Warrior Basin.

Hydraulic fracturing is a well-established 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

9




fractures in the target formation through which the natural gas and/or oil can flow. The fractures are created when a water-based fluid is pumped at a calculated rate and pressure into the natural gas- or crude oil-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.

Various 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 in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party under The Comprehensive Environmental Response, Compensation, and Liability Act 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. Due to its one time use of Reef Environmental 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 470 employees. On January 22, 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 and current oil and natural gas commodity prices. Energen believes that its relations with 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 and 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 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

If oil and natural gas prices remain at their current levels for an extended period of time or continue to decline, it could adversely affect our financial condition and results of operations.

Our revenues, cash flows and earnings are influenced predominantly by the amount of oil and natural gas we produce and the prices we receive for production. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, during the year ended December 31, 2015, commodity prices changed significantly, with the settlement price for West Texas Intermediate (WTI) crude oil ranging from a high of approximately $61.43 per barrel to a low of approximately $34.73 per barrel and settlement prices for Henry Hub natural gas ranging from a high of approximately $3.23 per Mcf to a low of approximately $1.76 per Mcf. Commodity price weakness has continued into 2016 and, through February 12, 2016, the WTI settlement price of crude oil had a low of approximately $26.21 per barrel, with a February 12, 2016 closing price of approximately $29.44 per barrel, and the Henry Hub settlement price of natural gas had a low of approximately $1.97 per Mcf, with a February 12, 2016 closing price of approximately $1.97 per Mcf.

In addition to reducing our revenue, cash flows and earnings, depressed prices for oil and natural gas may adversely affect us in a variety of ways. If commodity prices do not improve or further decrease, 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. 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 Note 1, Organization and Basis of Presentation, in the Notes to Financial Statements, and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Liquidity”, the Company discusses its plans regarding liquidity and covenant compliance for 2016.

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 business is significantly impacted by commodity prices, and historical markets for oil, natural gas liquids and natural gas have been volatile. Energen’s revenues, operating results, profitability and cash flows depend primarily upon the prices realized for our oil, natural gas liquids and natural gas production.

Approximately 59 percent of our December 31, 2015 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:


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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.

The decline since late 2014 in oil, natural gas liquids and natural gas prices has reduced our revenue and cash flows and, unless commodity prices improve, this trend will likely continue or worsen. Lower oil, natural gas liquids and natural gas prices also potentially reduce the amount of oil and natural gas that we can economically produce resulting in a reduction in the proved oil and natural gas reserves we could recognize. Thus, significant and sustained commodity price reductions could materially and adversely affect our financial condition and results of operations which could impact our ability to maintain or increase our current levels of borrowing, our ability to repay current or future indebtedness, our ability to refinance our current indebtedness or obtain additional capital on attractive terms.

We engage in derivative risk management activities in order to reduce our risks associated with commodity price fluctuations. We currently have significantly fewer hedges in place for 2016 and at lower price levels than in 2015 and may not be able to execute new hedges at acceptable volumes or price levels.

Revenues realized from hedging have also been significantly impacted by substantial reductions in oil, natural gas liquids and natural gas prices. During 2015, our hedges included 11,180 MBbl of crude oil production at an average NYMEX price of $82.34 per barrel and 29 Bcf of natural gas production at an average NYMEX equivalent price of $4.33 per Mcf. We currently have 2016 hedges of approximately 1,086 MBbl of our crude oil production hedged at an average NYMEX price of $63.80 per barrel. In addition, we have hedges of 6.6 Bcf of natural gas production at a NYMEX equivalent price of $2.47 per Mcf. Unless 2016 commodity prices increase, the net prices we will receive for our 2016 production will decline significantly from 2015 which will adversely affect our revenues and cash flows during 2016. Further, there is no assurance that commodity prices will not decline further and our ability to hedge against future commodity price declines may be significantly limited.

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.

The value of our proved reserves as of December 31, 2015 calculated using SEC pricing is higher than the fair market value of our proved reserves calculated using current market prices.

Our estimated proved reserves as of December 31, 2015 and related PV-10 and Standardized Measure were calculated under SEC rules using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices of $50.28 per barrel

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of crude oil, $0.41 per gallon of natural gas liquids and $2.59 per Mcf for natural gas. Those average prices are significantly above average prices experienced during late 2015 and early 2016, and, unless commodity prices improve, our estimated reserves and related present value calculations thereof will decline substantially from our December 31, 2015 calculations, and we may incur related impairment charges, which will materially adversely affect our results of operations in the period incurred.

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, 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 2016 and future years.

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

At December 31, 2015, approximately 95 percent and 5 percent of our total estimated proved reserves were attributable to properties located in the Permian Basin of west Texas and San Juan Basin of New Mexico, respectively. 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:
governmental regulation;
state politics;
processing or transportation capacity constraints;
market limitations;
water shortages, including restrictions on water usage or other drought related conditions or
interruption of the processing or transportation of oil, natural gas liquids or natural gas.

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

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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 from property sales. However, the current commodity price environment and conditions in our industry 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 October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion from $1.6 billion in association with the semi-annual redetermination required under the agreement. As of December 31, 2015, the Company had $222.5 million outstanding under its revolving credit facility. If commodity prices remain at current levels, we would expect a further reduction in our borrowing base at the next scheduled redetermination on April 1, 2016, and such reduction could be significant. A lowering of our borrowing base could require us to immediately repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral, if available. If our borrowing base decreases, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed to fund our capital expenditures, our ability to access the capital markets may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.

We are also subject to financial and non-financial covenants under the terms of our credit facility. The financial covenants in our credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other noncash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0. As of December 31, 2015, we were in compliance with our covenants. However, 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, at future measurement dates in 2016 and beyond. Such factors may include further 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, during 2016. 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, which is an aggregate balance outstanding of $776.5 million at December 31, 2015. 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 Note 1, Organization and Basis of Presentation, in the Notes to Financial Statements, and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Liquidity”, the Company discusses its plans regarding liquidity and covenant compliance for 2016.


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We recently announced the discontinuance of 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 and do not anticipate paying cash dividends on our common stock in 2016. 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.

Our San Juan Basin properties were classified as held for sale at December 31, 2015 and, subsequent to December 31, 2015, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale. and recent declines in prices for crude oil and natural gas could adversely affect our ability to sell these properties and the prices we may obtain for the sale of such properties, which could adversely affect our revenue, cash flows, financial condition, our ability to fund our capital spending and our ability to comply with financial covenants under our credit agreement.

Market conditions for crude oil and natural gas, particularly the recent decline in prices for crude oil and natural gas, could adversely affect market prices for oil and gas reserves. If we are unable to sell the properties we are seeking to sell or at prices which meet or exceed the fair value, our revenue, cash flows and financial condition may be adversely affected. Many companies that might otherwise be interested in pursuing the acquisition of these properties may not have the desire or the financial ability to pursue these acquisitions in the current depressed commodities price environment. This may reduce the pool of potential buyers and our competitors may be able to utilize the oil and gas market downturn to obtain properties at steep discounts and to execute transactions in an intensely competitive market. Our failure to dispose of properties, or at the sales prices which we anticipate, could have a material adverse effect on our revenues, cash flows, financial condition and our ability to comply with financial covenants under our credit agreement.

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.
The subject of climate change continues to receive attention from many parties including legislators and governmental agencies.
If additional 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. 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 addition, 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. If additional federal, state or local 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.

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. Texas has recently 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 or local legislation governing the disposal of drilling wastewater.

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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 is insufficient to fully recover the cost invested in the respective project, we will record an impairment loss in our statements of income. We recorded $1.3 billion of impairments during 2015 and, if the depressed commodity price environment continues, we may be required to record additional impairments during 2016.
 
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 continuation or worsening of the depressed 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, and it is difficult to predict how long the current depressed commodity price environment will continue and the ultimate impact it will have on the companies with which we do business.
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 last decade, could materially affect our operations, liquidity and financial condition through the adverse impacts such turmoil can have on the debt and equity capital markets. Market volatility and credit market disruption may severely limit credit availability, and issuer credit ratings can change rapidly. A significant reduction in cash flows from operations or the availability of credit could limit our ability to pursue acquisition opportunities or reduce cash flow used for drilling which could materially and adversely affect our ability to achieve our planned growth and operating results.
The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders and Energen. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition transactions involving Energen may negatively impact market and rating agency considerations regarding the credit of Energen, and management periodically considers these types of transactions.

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

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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 which has been adopted by the U.S. Congress, or additions to or changes in the legislation, could negatively impact our ability to use derivative instruments as part of our risk management activities.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets. The Commodities Futures Trading Commission (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.  We believe Energen’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act swap clearing and exchange-trading requirements pursuant to final regulations adopted by the CFTC and SEC.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require Energen, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. 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. 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.

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

Energen delivers to third-party facilities. These facilities include third-party oil and natural gas gathering, transportation, processing and storage facilities. Energen relies on such facilities for access to market for our oil, natural gas liquids and natural gas production. Such facilities are typically limited in number and geographically concentrated. A lack of available capacity on these facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties for Energen. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act, maintenance or otherwise could have an adverse effect on our revenues and results of operations.

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

We have identified drilling locations and prospects for future drilling, including development and exploratory drilling activities. Our ability to successfully and economically drill and develop these locations depends on a number of factors, including:
prices of oil, natural gas liquids and natural gas;
current laws or regulations or changes in the laws or regulations in 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.

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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 materially 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

19



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 21, 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 district offices in Midland, Texas and Farmington, New Mexico.




The major areas of operations include (1) the Permian Basin and (2) the San Juan Basin as highlighted on the above map. At December 31, 2015, our San Juan Basin properties were classified as held for sale.

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

 
Year ended
 
 
 
December 31, 2015
December 31, 2015
December 31, 2015
 
Production Volumes
(MBOE)
Proved Reserves (MBOE)
Proved Reserves-to-Production Ratio
Permian Basin
20,664

337,008

16.31 years
San Juan Basin*
3,322

16,930

5.10 years
Other
36

784

21.78 years
Total
24,022

354,722

14.77 years
*San Juan Basin assets were classified as held for sale as of December 31, 2015.


20



The following table sets forth proved reserves by area as of December 31, 2015:

 
Oil MBbl
NGL MBbl
Natural Gas MMcf
Total MBOE
Permian Basin
207,593

66,023

380,358

337,008

San Juan Basin*
2,829

5,668

50,588

16,930

Other
269

22

2,958

784

Total
210,691

71,713

433,904

354,722

*San Juan Basin assets were classified as held for sale as of December 31, 2015.

See Note 21, Oil and Natural Gas Operations (Unaudited), in the Notes to Financial Statements for the changes to proved reserves during the years ended December 31, 2015, 2014 and 2013 of oil, natural gas liquids and natural gas.

The following table sets forth proved developed reserves by area as of December 31, 2015:

 
Oil MBbl
NGL MBbl
Natural Gas MMcf
Total MBOE
Permian Basin
106,123

30,932

184,095

167,736

San Juan Basin*
1,927

5,420

49,059

15,525

Other
269

22

2,958

784

Total
108,319

36,374

236,112

184,045

*San Juan Basin assets were classified as held for sale as of December 31, 2015.

The following table sets forth proved undeveloped reserves by area as of December 31, 2015:

 
Oil MBbl
NGL MBbl
Natural Gas MMcf
Total MBOE
Permian Basin
101,470

35,091

196,263

169,272

San Juan Basin*
902

248

1,529

1,405

Total
102,372

35,339

197,792

170,677

*San Juan Basin assets were classified as held for sale as of December 31, 2015.

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

Year ended December 31, 2015
Total MMBOE
Balance at beginning of period
108.2
Undeveloped reserves transferred to developed reserves
(17.4)
Revisions
(23.5)
Extensions and discoveries
103.4
Balance at end of period
170.7

Proved undeveloped reserves transferred to proved developed reserves reflect capital expenditures of approximately $232 million during the year ended December 31, 2015 in development of previously proved undeveloped reserves. Proved undeveloped reserves additions included proved undeveloped reserve locations one offset away from producing wells and proved undeveloped reserve locations that are more than one offset away from producing wells using reliable technology and where our geologic interpretation and experience indicate the reservoirs are continuous across those locations. The technologies associated with these additions to proved reserve estimates included analysis of well production data, geophysical data, wireline data, core data and interpretation of zonal analysis. Negative revisions are due to 11.9 MMBOE related to changes in year end pricing, 8.2 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period and 3.3 MMBOE of Wolfcamp reserves due to interference caused by our wellbore placement geometry.


21



Estimated proved reserves as of December 31, 2015 are based upon studies for each of our properties prepared by Company engineers and audited by Ryder Scott Company, L.P. (Ryder Scott) and Hickman McClaine and Associates, Inc. (Hickman McClaine), 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. A Petroleum Consultant at Hickman McClaine is the technical person primarily responsible for overseeing the audit of the reserves. He has a Bachelor of Science degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has been employed by Hickman McClaine since 1983. Energen Resources’s Vice President of Acquisitions and Reservoir Engineering is the technical person primarily responsible for overseeing reserves on behalf of Energen. His background includes a Bachelor of Science degree in Mechanical Engineering and membership in the Society of Petroleum Engineers. He is a registered Professional Engineer in the State of Alabama with more than 30-years 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 of Acquisitions and 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 2015, 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 each state 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, 2015, 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
5,327

3,483

216,515

80,242

San Juan Basin*
492

439

82,955

49,398

Other
80

6

20,108

6,576

Total
5,899

3,928

319,578

136,216

*San Juan Basin assets were classified as held for sale as of December 31, 2015.







22



The following table sets forth expiration dates for gross and net undeveloped acreage at year end as of December 31, 2015:

 
Years ending December 31,
 
2016
2017
2018
Thereafter
 
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Permian
33,617

22,986

26,596

16,189

13,954

15,420

29,520

25,647

San Juan/other*
12,309

4,992

16,712

9,179

12,352

11,930

40,994

29,873

Total
45,926

27,978

43,308

25,368

26,306

27,350

70,514

55,520

*Other includes a total of 14,694 gross (6,576 net) acreage 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, 2015, Energen had approximately 354.7 MMBOE total proved reserves which included 170.7 MMBOE of proved undeveloped reserves. We had approximately 24.7 MMBOE or 14.4 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.

Energen sells oil, natural gas liquids, and natural gas under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity (firm volumes). Energen is contractually committed to deliver approximately 0.9 Bcf (net) of natural gas from the San Juan Basin through March 2016. We expect to fulfill delivery commitments through production of existing proved reserves.

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. 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


23



EXECUTIVE OFFICERS OF THE REGISTRANT

Name
Age
Position (1)
James T. McManus, II
57
Chairman, Chief Executive Officer and President of Energen (2)
Charles W. Porter, Jr.
51
Vice President, Chief Financial Officer and Treasurer of Energen (3)
John S. Richardson
58
President and Chief Operating Officer of Energen Resources (4)
J. David Woodruff, Jr.
59
Vice President, General Counsel and Secretary of Energen (5)
David A. Godsey
61
Senior Vice President – Exploration and Geology of Energen Resources (6)
Russell E. Lynch, Jr.
42
Vice President and Controller of Energen (7)

Notes:    
(1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years except for Mr. Godsey. 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. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003. He also served as Vice President –Corporate Development of Energen from 1995 to 2010.

(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. 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.

24




PART II

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

Quarterly Market Prices and Dividends Paid Per Share
 
 
 
 
 
Quarter ended
High
Low
Close
Dividends Paid
March 31, 2014
$83.65
$65.35
$80.81
$0.15
June 30, 2014
$90.66
$76.42
$88.88
$0.15
September 30, 2014
$90.50
$71.24
$72.24
$0.15
December 31, 2014
$73.21
$53.78
$63.76
$0.02
March 31, 2015
$71.75
$57.71
$66.00
$0.02
June 30, 2015
$77.12
$65.53
$68.30
$0.02
September 30, 2015
$69.11
$43.75
$49.86
$0.02
December 31, 2015
$61.98
$39.99
$40.99
$0.02

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On January 25, 2016, there were 4,383 holders of record of Energen common stock. In February 2016, we announced the discontinuance of dividend payments. Accordingly, we do not expect to pay cash dividends on Energen common stock in 2016. 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.

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, 2015 - October 31, 2015
545

*
$
59.66


3,373,161
November 1, 2015 - November 30, 2015

 


3,373,161
December 1, 2015 - December 31, 2015
5,569

*
48.40


3,373,161
Total
6,114

 
$
49.40


3,373,161
*Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.
**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.


25




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, 2010, in the Company and each of the indices. Total shareholder return includes reinvested dividends.




As of December 31,
2010
2011
2012
2013
2014
2015
S&P 500
$
100

$
102

$
118

$
157

$
178

$
181

Energen
$
100

$
105

$
96

$
152

$
138

$
89

S15OILP
$
100

$
92

$
94

$
121

$
106

$
69



26




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)
2015
 
2014
 
2013
 
2012
 
2011
INCOME STATEMENT
 
 
 
 
 
 
 
 
 
Total revenues
$
878,554

 
$
1,679,213

 
$
1,206,293

 
$
1,090,948

 
$
834,700

Income from continuing operations
$
(945,731
)
 
$
99,643

 
$
141,881

 
$
204,621

 
$
174,686

Net income
$
(945,731
)
 
$
568,032

 
$
204,554

 
$
253,562

 
$
259,624

Diluted earnings per average common share from continuing operations
$
(12.43
)
 
$
1.36

 
$
1.96

 
$
2.83

 
$
2.42

Diluted earnings per average common share
$
(12.43
)
 
$
7.75

 
$
2.82

 
$
3.51

 
$
3.59

BALANCE SHEET
 
 
 
 
 
 
 
 
 
Total property, plant and equipment, net
$
4,350,690

 
$
5,199,137

 
$
5,118,088

 
$
4,698,951

 
$
3,807,305

Total assets
$
4,613,693

 
$
6,138,258

 
$
6,622,212

 
$
6,175,890

 
$
5,237,416

Long-term debt
$
776,087

 
$
1,038,563

 
$
1,093,541

 
$
903,500

 
$
904,454

Total shareholders’ equity
$
2,895,860

 
$
3,414,604

 
$
2,858,019

 
$
2,676,690

 
$
2,432,163

COMMON STOCK DATA
 
 
 
 
 
 
 
 
 
Cash dividends paid per common share
$
0.08

 
$
0.47

 
$
0.58

 
$
0.56

 
$
0.54

Diluted average common shares outstanding (000)
76,078

 
73,275

 
72,471

 
72,316

 
72,332

Price range:
 
 
 
 
 
 
 
 
 
High
$
77.12

 
$
90.66

 
$
89.92

 
$
58.24

 
$
65.44

Low
$
39.99

 
$
53.78

 
$
44.46

 
$
40.13

 
$
37.22

Close
$
40.99

 
$
63.76

 
$
70.75

 
$
45.09

 
$
50.00



























27




SELECTED BUSINESS DATA

Years ended December 31,
(dollars in thousands, except per unit data)
2015
 
2014
 
2013
 
2012
 
2011
Oil, natural gas liquids and natural gas sales from continuing operations
 
 
 
 
 
 
Oil
$
631,663

 
$
988,868

 
$
961,055

 
$
766,105

 
$
570,413

Natural gas liquids
48,856

 
110,918

 
91,407

 
81,313

 
101,818

Natural gas
82,742

 
244,408

 
203,855

 
159,377

 
210,813

Total
$
763,261

 
$
1,344,194

 
$
1,256,317

 
$
1,006,795

 
$
883,044

Open non-cash mark-to-market gains (losses) on derivative instruments
 
Oil
$
(242,227
)
 
$
271,200

 
$
(43,261
)
 
$
58,786

 
$
(37,473
)
Natural gas liquids

 
287

 
(652
)
 
479

 
(114
)
Natural gas
(39,525
)
 
43,958

 
(3,919
)
 
(515
)
 

Total
$
(281,752
)
 
$
315,445

 
$
(47,832
)
 
$
58,750

 
$
(37,587
)
Closed gains (losses) on derivative instruments
 
Oil
$
346,404

 
$
4,377

 
$
(52,694
)
 
$
(35,954
)
 
$
(67,205
)
Natural gas liquids

 
6,218

 
10,795

 
4,146

 
(14,240
)
Natural gas
50,641

 
8,979

 
39,707

 
57,211

 
70,688

Total
$
397,045

 
$
19,574

 
$
(2,192
)
 
$
25,403

 
$
(10,757
)
Total revenues
$
878,554

 
$
1,679,213

 
$
1,206,293

 
$
1,090,948

 
$
834,700

Production volumes from continuing operations
 
 
 
 
 
 
 
 
 
Oil (MBbl)
14,023

 
11,814

 
10,364

 
8,749

 
6,300

Natural gas liquids (MMgal)
170.7

 
172.3

 
135.8

 
108.1

 
91.4

Natural gas (MMcf)
35,604

 
58,602

 
58,104

 
59,166

 
54,132

Production volumes from continuing operations (MBOE)
24,022

 
25,684

 
23,281

 
21,183

 
17,499

Total production volumes (MBOE)
24,022

 
25,849

 
25,362

 
24,066

 
20,448

Proved reserves
 
 
 
 
 
 
 
 
 
Oil (MBbl)
210,691

 
181,227

 
164,870

 
155,348

 
129,578

Natural gas liquids (MBbl)
71,713

 
73,463

 
63,011

 
56,155

 
53,957

Natural gas (MMcf))
433,904

 
707,926

 
719,725

 
809,128

 
957,368

Total (MBOE)
354,722

 
372,678

 
347,835

 
346,359

 
343,099

Costs per BOE from continuing operations
 
 
 
 
 
 
 
 
 
Oil, natural gas liquids and natural gas production expenses
$
9.51

 
$
10.68

 
$
11.06

 
$
9.55

 
$
9.11

Production and ad valorem taxes
$
2.39

 
$
3.97

 
$
4.04

 
$
3.58

 
$
3.82

Depreciation, depletion and amortization
$
24.72

 
$
21.36

 
$
19.45

 
$
16.17

 
$
12.19

Exploration expense
$
0.62

 
$
1.09

 
$
0.60

 
$
0.62

 
$
0.74

General and administrative expense
$
6.21

 
$
4.75

 
$
4.89

 
$
3.71

 
$
4.41

Net capital expenditures
$
1,040,610

 
$
1,372,510

 
$
1,104,745

 
$
1,291,211

 
$
1,115,452

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

28



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 primarily in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources). At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale.

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. 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 Year-to-Date 2015 Results and Activities
During the year ended December 31, 2015 as compared to the same period in the prior year, we:
expanded development and exploratory activities in the Permian Basin, increasing production by 19.5 percent or 3,366 MBOE;
experienced a significant decline in commodity prices;
recognized non-cash impairments on certain oil properties in the Delaware Basin and Central Basin Platform of the Permian Basin of $1,092.2 million pre-tax;
recognized non-cash impairments on certain held for sale properties in the San Juan Basin of $133.1 million pre-tax (see Note 15, Acquisition and Disposition of Properties, in the Notes to Financial Statements);
recognized unproved leasehold writedowns on San Juan Basin properties of $37.9 million pre-tax;
recognized unproved leasehold writedowns on Permian Basin oil properties of $29.2 million pre-tax;
issued 5,700,000 additional shares of common stock through a public equity offering receiving net proceeds of approximately $398.6 million and
completed the sale of the majority of our natural gas assets in the San Juan Basin in New Mexico and Colorado for an aggregate purchase price of approximately $395 million on March 31, 2015.

Year ended December 31, 2015 vs year ended December 31, 2014
Energen’s net loss for the year ended December 31, 2015 totaled $945.7 million ($12.43 per diluted share) compared to the year ended December 31, 2014 net income of $568.0 million ($7.75 per diluted share). Energen’s loss from continuing operations totaled $945.7 million ($12.43 per diluted share) in 2015 as compared with income from continuing operations of $99.6 million ($1.36 per diluted share) in 2014. Energen did not have discontinued operations for the current year. Income from discontinued operations was $468.4 million ($6.39 per diluted share) in 2014 largely due to the sale of Alagasco. This change in income (loss) from continuing operations was primarily the result of:

lower realized oil, natural gas liquids and natural gas commodity prices (approximately $428 million after-tax);
year-over-year after-tax $382.9 million loss on open derivatives (resulting from an after-tax $181.3 million non-cash loss on open derivatives for 2015 and an after-tax $201.8 million non-cash gain on open derivatives for 2014);
non-cash impairments 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);
non-cash impairments on certain held for sale properties in the San Juan Basin (approximately $85.1 million after-tax);
decreased natural gas and natural gas liquids production volumes (approximately $62 million after-tax);
higher depreciation, depletion and amortization (DD&A) expense (approximately $29 million after-tax);
unproved leasehold writedowns on San Juan Basin properties (approximately $24.3 million after-tax);
additional unproved leasehold writedowns primarily on Permian Basin properties in the Delaware Basin (approximately $18.7 million after-tax);
increased general and administrative expense (approximately $17 million after-tax) and
increased interest expense (approximately $3 million after-tax)

29




partially offset by:

gain on closed derivatives (approximately $242 million after-tax);
non-cash impairments in 2014 on certain gas properties in the San Juan Basin (approximately $143.7 million after-tax);
higher oil production volumes (approximately $118 million after-tax);
non-cash impairments in 2014 on certain oil properties in the Permian Basin (approximately $70.9 million after-tax);
unproved leasehold writedowns in 2014 on Permian Basin oil properties (approximately $39 million after-tax) and unproved leasehold writedowns on San Juan Basin properties (approximately $3.7 million after-tax);
decreased oil, natural gas liquids and natural gas production expense (approximately $29 million after-tax);
lower production and ad valorem taxes (approximately $29 million after-tax);
gain on sale of the majority of our natural gas assets in the San Juan Basin (approximately $17.3 million after tax) and
lower exploration expense (approximately $8 million after-tax).

Year ended December 31, 2014 vs year ended December 31, 2013
For the year ended December 31, 2014, Energen’s net income totaled $568.0 million ($7.75 per diluted share) as compared to net income of $204.6 million ($2.82 per diluted share) in 2013. Energen’s income from continuing operations totaled $99.6 million ($1.36 per diluted) in 2014 as compared with $141.9 million ($1.96 per diluted) in 2013. Income from discontinued operations for 2014 was $468.4 million ($6.39 per diluted share) as compared with income of $62.7 million ($0.86 per diluted share) from 2013 largely due to the sale of Alagasco. This decrease in income from continuing operations was primarily the result of:

non-cash impairments on certain gas properties in the San Juan Basin (approximately $143.7 million after-tax);
non-cash impairments on certain oil properties in the Permian Basin (approximately $70.9 million after-tax);
unproved leasehold writedowns primarily on Permian Basin oil properties (approximately $39 million after-tax);
lower realized oil and natural gas liquids commodity prices (approximately $72 million after-tax);
higher depreciation, depletion and amortization (DD&A) expense (approximately $62 million after-tax);
higher oil, natural gas liquids and natural gas production expense (approximately $11 million after-tax);
higher exploration expense (approximately $9 million after-tax);
increased general and administrative expense (approximately $5 million after-tax) and
higher production and ad valorem taxes (approximately $5 million after-tax)

partially offset by:

year-over-year after-tax $232.4 million gain on open derivatives (resulting from an after-tax $201.8 million non-cash gain on open derivatives for 2014 and an after-tax $30.6 million non-cash loss on open derivatives for 2013);
higher oil, natural gas liquids and natural gas production volumes (approximately $104 million after-tax);
higher realized natural gas commodity prices (approximately $25 million after-tax) and
gain on closed derivatives (approximately $14 million after-tax).

Operating Income (Loss)
Operating loss in 2015 totaled $1,437.9 million. Operating income in 2014 and 2013 totaled $177.0 million and $252.1 million, respectively. Reduced operating income for 2015 is primarily due to significantly lower commodity prices, asset impairment charges, non-cash mark-to-market decrease in open derivatives, decreased natural gas and natural gas liquids production and higher DD&A expense partially offset by non-cash mark-to-market increase in closed derivatives, higher oil production, lower oil, natural gas liquids and natural gas production expense, decreased production and ad valorem taxes and a gain on the sale of certain natural gas San Juan Basin assets. In 2014, lower operating income was largely due to non-cash impairments on certain properties in the San Juan and Permian basins, leasehold writedowns in the Permian Basin, lower oil and natural gas liquids commodity prices and higher DD&A expense. Partially offsetting these decreases in operating income was the non-cash mark-to-market income in open and closed derivatives, higher production and increased natural gas commodity prices.












30




Results of Operations
The following table summarizes information regarding our production and operating data from continuing operations.

Years ended December 31,
(in thousands, except sales price and per unit data)
2015
2014
2013
Operating and production data from continuing operations
 
 
 
Oil, natural gas liquids and natural gas sales
 
 
 
Oil
$
631,663

$
988,868

$
961,055

Natural gas liquids
48,856

110,918

91,407

Natural gas
82,742

244,408

203,855

Total
$
763,261

$
1,344,194

$
1,256,317

Open non-cash mark-to-market gains (losses) on derivative instruments
 
 
Oil
$
(242,227
)
$
271,200

$
(43,261
)
Natural gas liquids

287

(652
)
Natural gas
(39,525
)
43,958

(3,919
)
Total
$
(281,752
)
$
315,445

$
(47,832
)
Closed gains (losses) on derivative instruments
 
 
Oil
$
346,404

$
4,377

$
(52,694
)
Natural gas liquids

6,218

10,795

Natural gas
50,641

8,979

39,707

Total
$
397,045

$
19,574

$
(2,192
)
Total revenues
$
878,554

$
1,679,213

$
1,206,293

Production volumes
 
 
 
Oil (MBbl)
14,023

11,814

10,364

Natural gas liquids (MMgal)
170.7

172.3

135.8

Natural gas (MMcf)
35,604

58,602

58,104

Total production volumes (MBOE)
24,022

25,684

23,281

Average daily production volumes
 
 
 
Oil (MBbl)
38.4

32.4

28.4

Natural gas liquids (MMgal)
0.5

0.5

0.4

Natural gas (MMcf)
97.5

160.6

159.2

Total average daily production volumes (MBOE/d)
65.8

70.4

63.8

Permian Basin - Spraberry (Trend Area) Field production volumes (included in production volumes above)*
Oil (MBbl)
2,143

2,463

2,822

Natural gas liquids (MMgal)
30.9

44.5

38.5

Natural gas (MMcf)
4,313

5,729

4,836

Total production volumes (MBOE)
3,599

4,477

4,544

Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)
$
69.75

$
84.07

$
87.65

Natural gas liquids (per gallon)
$
0.29

$
0.68

$
0.75

Natural gas (per Mcf)
$
3.75

$
4.32

$
4.19

Average realized prices excluding effects of all derivative instruments
Oil (per barrel)
$
45.04

$
83.70

$
92.73

Natural gas liquids (per gallon)
$
0.29

$
0.64

$
0.67


31




Natural gas (per Mcf)
$
2.32

$
4.17

$
3.51

Costs per BOE
 
 
 
Oil, natural gas liquids and natural gas production expenses
$
9.51

$
10.68

$
11.06

Production and ad valorem taxes
$
2.39

$
3.97

$
4.04

Depreciation, depletion and amortization
$
24.72

$
21.36

$
19.45

Exploration expense
$
0.62

$
1.09

$
0.60

General and administrative
$
6.21

$
4.75

$
4.89

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

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

For the year ended December 31, 2015, commodity sales decreased $580.9 million or 43.2 percent from the same period of 2014. Particular factors impacting commodity sales for 2015 include the following:

Oil volumes in 2015 increased 18.7 percent to 14,023 MBbl as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins more than offset declines in the Wolfberry in the Midland Basin, 3rd Bone Spring in the Delaware Basin and the Central Basin Platform.
Average realized oil prices fell 46.2 percent to $45.04 per barrel during 2015.
Natural gas liquids production for 2015 declined 0.9 percent to 170.7 MMgal due to the sale of the majority of our natural gas assets in the San Juan Basin.
Average realized natural gas liquids prices decreased 54.7 percent to an average price of $0.29 per gallon during 2015.
Natural gas production decreased 39.2 percent to 35.6 Bcf in 2015 due to the sale of natural gas assets in the San Juan Basin, normal declines in the San Juan Basin and pipeline curtailments in the Permian Basin partially offset by accelerated completions and new well performance in the Permian Basin.
Average realized natural gas prices decreased 44.4 percent to $2.32 per Mcf during 2015.
Production from continuing operations fell 6.5 percent to 24 MMBOE during 2015.

For the year ended December 31, 2014, oil, natural gas liquids and natural gas sales increased $87.9 million or 7 percent from the same period of 2013. Particular factors impacting commodity sales for 2014 include the following:

Oil volumes rose 14 percent to 11,814 MBbl during 2014 as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins, along with continued Wolfberry and Bone Spring drilling, more than offset declines in the mature Central Basin Platform.
Average realized oil prices in 2014 fell 9.7 percent to $83.70 per barrel and included the impact of wider oil basis differentials.
Production of natural gas liquids increased 26.9 percent to 172.3 MMgal in 2014 largely due to higher natural gas volumes related to the current drilling program and higher natural gas liquids recovery.
Average realized natural gas liquids prices fell 4.5 percent to an average price of $0.64 per gallon during 2014.
Natural gas production increased 0.9 percent to 58.6 Bcf in 2014 as increased production in the Permian Basin was partially offset by declining San Juan Basin production.
Average realized natural gas prices in 2014 rose 18.8 percent to $4.17 per Mcf.
Production from continuing operations rose 10.3 percent to 25.7 MMBOE during 2014.

Realized prices exclude the effects of derivative instruments.









32




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)
2015
2014
2013
Lease operating expenses
$
140,010

$
140,413

$
129,326

Workover and repair costs
68,428

91,629

84,102

Marketing and transportation
19,942

42,390

44,010

Total oil, natural gas liquids and natural gas production expense
$
228,380

$
274,432

$
257,438

Oil, natural gas liquids and natural gas production expense per BOE
$
9.51

$
10.68

$
11.06


Energen had oil, natural gas liquids and natural gas production expense of $228.4 million, $274.4 million and $257.4 million during the years ended December 31, 2015, 2014 and 2013, respectively. Lease operating expense may be positively or negatively impacted by property acquisitions and dispositions and also generally reflects year-over-year increases in the number of active wells resulting from Energen’s ongoing development and exploratory activities. Overall lease operating expense was positively impacted in the current year by the sale of the San Juan Basin.

In 2015, lease operating expense decreased $0.4 million primarily due to lower other operations and maintenance expense (approximately $8 million) and decreased electrical costs (approximately $3.6 million) largely offset by additional equipment rental costs (approximately $4.5 million), higher labor costs (approximately $2 million), increased non-operated costs (approximately $1.9 million), increased gathering costs (approximately $1.2 million), higher environmental compliance costs (approximately $1.1 million) and higher water disposal costs (approximately $1.1 million).

In 2014, lease operating expense increased $11.1 million primarily due to increased chemical and treatment costs (approximately $2.7 million), higher producing overhead costs (approximately $2.2 million), increased gathering costs (approximately $2.2 million), additional other operations and maintenance expense (approximately $1.9 million), increased labor costs (approximately $1.7 million), higher electrical costs (approximately $1.7 million) and increased non-operated costs (approximately $1.6 million) partially offset by decreased environmental compliance costs (approximately $2.9 million) and lower water disposal costs (approximately $1 million).

On a per unit basis, the average lease operating expense for 2015, 2014 and 2013 was $5.83 per BOE, $5.46 per BOE and $5.56 per BOE, respectively.

Workover and repair costs decreased approximately $23.2 million in 2015 and increased $7.5 million in 2014. Workover and repair costs in 2015 were lower primarily due to lower incidence of offset well stimulation interference and lower electrical costs. In 2014, these expenses were primarily related to workovers in the west Texas Permian Basin associated with pump and tubing replacements. Additional expenses were incurred associated with the protective preparation of producing wells for offset operations. Also, the increased number of producing wells resulting from our ongoing drilling program creates a higher level of base load workover and repair expense.

In the years ended December 31, 2015 and 2014, marketing and transportation costs decreased $22.4 million and $1.6 million, respectively. The decline in 2015 was largely due to lower natural gas volumes as a result of the sale of certain San Juan Basin natural gas assets.

Production and ad valorem taxes: Production and ad valorem taxes were $57.4 million ($2.39 per BOE), $102.1 million ($3.97 per BOE) and $94.1 million ($4.04 per BOE) during the years ended December 31, 2015, 2014 and 2013, respectively. In 2015, production-related taxes were $37.1 million lower as decreased commodity market prices and lower net production volumes contributed approximately $32.2 million and $4.9 million to the decrease in production taxes, respectively. In 2014, production-related taxes were $7.8 million higher as increased commodity production volumes contributed approximately $7 million to the increase in production taxes combined with increased natural gas commodity market prices, largely offset by lower gas and natural gas liquids commodity market prices, which contributed approximately $0.8 million to the increase. Commodity market prices exclude the effects of derivative instruments for purposes of determining production taxes. Decreased ad valorem taxes of $7.6 million in 2015 were largely driven by the factor adjusted price impact on our Texas oil and natural gas properties. Increased ad valorem taxes of $0.2 million in 2014 were primarily driven by the increase in the number of active wells.


33




Depreciation, depletion and amortization: DD&A expense increased $45.2 million in 2015 and $95.7 million in 2014. The average DD&A rates were $24.72 per BOE in 2015, $21.36 per BOE in 2014 and $19.45 per BOE in 2013. The increase in the 2015 and 2014 per unit DD&A rates, which contributed approximately $79.3 million and $47.5 million, respectively, to the increase in DD&A expense, was primarily due to higher rates resulting from an increase in development costs and the impact of year end reserve revisions driven by lower commodity prices. Lower net production volumes reduced DD&A expense approximately $35.2 million in 2015. Increased production volumes contributed approximately $46.4 million to the increase in DD&A expense in 2014.

Asset impairment: Non-cash impairment writedowns are reflected in asset impairment on the consolidated income statements.

Permian Basin: 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. 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. During the fourth quarter of 2015, Energen recognized non-cash impairment writedowns of $646.1 million due to commodity price declines and the related impact to our drilling plans. Our commodity price assumptions declined over the third quarter by approximately 12 percent for oil and 6 percent for natural gas in comparable periods. During the third quarter of 2015, Energen recognized non-cash impairment writedowns of $390.2 million due to commodity price declines. Our commodity price assumptions declined over the second quarter by approximately 19 percent for oil and 12 percent for natural gas in comparable periods. During the second quarter of 2015, Energen recognized non-cash impairment writedowns on certain properties in the Central Basin Platform of $51.5 million. Estimated future cash flows were revised due to the receipt of an unsolicited offer for these properties. During the first quarter of 2015, Energen recognized a non-cash impairment writedown of $4.3 million.

During the third and fourth quarters of 2014, Energen recognized non-cash impairment writedowns on certain Permian Basin properties in the Midland Basin of $25.8 million and in the Delaware Basin of $90.6 million, respectively, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows.

Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties in the Delaware Basin of $29.2 million in 2015. During 2014, Energen recognized unproved leasehold writedowns of $64.4 million. These unproved leasehold writedowns include $55.1 million of leasehold expirations.

San Juan Basin: 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. At December 31, 2015, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 16,930 MBOE.

During the third and fourth quarters of 2014, non-cash impairment writedowns of $142.2 million and $88.1 million, respectively, were recognized by Energen on certain natural gas properties in the San Juan Basin to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows in the third quarter and based on direct market data in the fourth quarter as these properties were designated as held for sale as of December 31, 2014. At December 31, 2014, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 69,038 MBOE.

During 2015 and 2014, Energen recognized unproved leasehold writedowns San Juan Basin properties of $37.9 million and $5.8 million, respectively.

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

Years ended December 31, (in thousands, except per unit data)
2015
2014
2013
Geological and geophysical
$
7,316

$
8,800

$
3,141

Dry hole costs
7,097

9,325

2,101

Delay rentals and other
465

9,965

8,794

Total exploration expense
$
14,878

$
28,090

$
14,036

Total exploration expense per BOE
$
0.62

$
1.09

$
0.60


Exploration expense decreased $13.2 million in 2015 primarily due to lower delay rentals and dry hole costs. Delay rentals are lower in the current year largely due to the sale of certain San Juan Basin properties. Exploration expense rose $14.1 million during 2014 primarily due to higher dry hole costs, increased seismic costs and additional delay rentals.

34




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

Years ended December 31, (in thousands, except per unit data)
2015
2014
2013
General and administrative
$
30,578

$
25,519

$
25,310

Benefit and performance-based compensation costs
64,805

45,215

45,954

Labor costs
53,749

51,318

42,557

Total general and administrative expense
$
149,132

$
122,052

$
113,821

Total general and administrative expense per BOE
$
6.21

$
4.75

$
4.89


In 2015, total G&A expense rose $27.1 million primarily due to increased costs related to Energen’s benefit and performance-based compensation plans (approximately $19.6 million), increased legal expenses (approximately $5.4 million) and higher labor costs (approximately $2.4 million). Total G&A expense rose $8.2 million in 2014 largely due to increased labor costs (approximately $8.8 million), higher professional services (approximately $1.6 million) and increased recruiting expenses (approximately $1.5 million) partially offset by decreased costs from Energen’s benefit and performance-based compensation plans (approximately $0.7 million) and decreased legal expenses (approximately $1.7 million). Included in costs from the benefit and performance-based compensation plans were pension costs of $31.3 million (including settlement expense of $29.8 million), $18.9 million (including settlement expense of $4.1 million) and $11.8 million (including settlement expense of $0.2 million) for the years ended December 31, 2015, 2014 and 2013, respectively.

(Gain) loss on sale of assets and other, net: 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 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 $5.3 million during 2015 largely due to the classification of interest expense associated with debt required to be extinguished as discontinued operations in the prior year partially offset by the prior year write-off of debt issuance costs associated with the $600 million Senior Term Loans. Interest expense decreased $2 million during 2014 largely due to the December 2013 repayment of the Senior Term Loans of $300 million issued in November 2011 and the October 2013 repayment of $50 million of 5 percent Notes, partially offset by the write-off of debt issuance costs of $2.7 million associated with the $600 million Senior Term Loans issued in December 2013, interest expense incurred from our credit facility entered into on September 2, 2014 and $0.4 million associated with the October 2012 syndicated credit facilities. The interest expense associated with the $600 million Senior Term Loans and the October 2012 syndicated credit facilities are reflected in discontinued operations for 2014 and 2013. In conjunction with the sale of Alagasco, the $600 million Senior Term Loans and the syndicated credit facilities were repaid in September 2014. The average daily outstanding balance under credit facilities was $358.9 million in 2015. The average daily outstanding balance under credit facilities was $482.2 million in 2014 as compared to $772 million in 2013.

Income tax expense: Income tax expense decreased in 2015 and 2014 largely due to lower pre-tax income. In addition, Energen recognized a $1.2 million and an $8.4 million income tax benefit during the 4th quarter of 2015 and 2014, respectively, as a result of re-measuring its state deferred tax liabilities. This re-measurement reflected the state apportionment changes related to certain San Juan Basin properties designated as held for sale as of December 31, 2015 and 2014. On June 15, 2015, a Texas tax bill was signed into law which reduces the Texas Franchise Tax (Margin Tax) rate from 1 percent to 0.75 percent for taxpayers not engaged in retail or wholesale trade. The tax rate reduction is applicable for tax reports originally due on or after January 1, 2016.  Energen recognized a $3.1 million income tax benefit during the second quarter of 2015, the period the law was enacted, to reflect the impact of this change.

Discontinued operations, net of tax: On September 2, 2014, Energen completed the transaction to sell Alagasco to Laclede for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion. This sale had an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. Energen’s results of operations and cash flows for the years ended December 31, 2014 and 2013 presented in our consolidated financial statements and these notes reflect Alagasco as discontinued operations.


35




In March 2014, Energen completed the sale of its North Louisiana/East Texas primarily natural gas properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized non-cash impairment writedowns on these properties in 2014 of $1.9 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. Energen also recognized non-cash impairment writedowns on these properties of $29.8 million in 2013. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net on the consolidated income statements. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million. Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 that was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013.

See Note 16, Discontinued Operations and Held for Sale Properties, in the Notes to Financial Statements for additional information regarding discontinued operations.

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 supplemented by borrowings under our syndicated credit facility to fund our capital spending plans and working capital requirements. We also used the pre-tax proceeds from the sale of certain San Juan Basin properties.

Net cash provided by operating activities: Energen’s net cash from operating activities totaled $714.6 million, $705.5 million and $927.4 million in 2015, 2014 and 2013, respectively and included discontinued operations associated with cash flows from Alagasco of $91.5 million in 2014 and $109.3 million in 2013. Net income in 2015 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 significantly lower commodity prices. During 2014, operating cash flows decreased due to lower oil and natural gas liquids commodity prices partially offset by increased production and higher natural gas commodity prices. Net income in 2014 was also significantly impacted by non-cash charges, including higher DD&A, asset impairment charges and the change in derivative fair value. During 2013, operating cash flows increased due to an increase in oil and natural gas liquids production and higher natural gas and oil commodity prices. In 2013, net income was also impacted by non-cash charges, including higher DD&A and the change in derivative fair value. The Company’s working capital needs were also influenced by accrued taxes and the timing of payments and recoveries for all years.

Net cash used in investing activities: Energen made net investments of $847.3 million during 2015. 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 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 2014, the Company made net investments of $38.9 million. Energen invested $70.7 million in property acquisitions including approximately $68.5 million of unproved leaseholds; $399.1 million for development costs (excludes the accrual of approximately $4.6 million of accrued development cost) including approximately $270 million to drill 102 net development and service wells; and $844.1 million for exploration (excludes the accrual of approximately $109.3 million of accrued exploration cost) including approximately $703 million to drill 110 net exploratory wells. Included in the proceeds from asset sales and the sale of Alagasco in 2014 are cash proceeds of $1,317.1 million from the sale of Alagasco and $30 million from the sale of North Louisiana/East Texas properties. During 2013, the Company made net investments of $1,053.6 million. Energen invested $31.3 million in property acquisitions including approximately $26.8 million of unproved leaseholds; $675.4 million for development costs (includes the reversal of approximately $23.9 million of accrued development cost) including approximately $457 million to drill 179 net development and service wells; and $423.7 million for exploration including approximately $295 million to drill 90 net exploratory wells. Energen had cash proceeds in 2013 of $161.0 million primarily from the sale of certain Black Warrior Basin properties.


36




During 2015, Energen added 133 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 130 MMBOE and 37 MMBOE of proved reserves in 2014 and 2013, respectively.

Net cash provided by (used in) financing activities: The Company provided $132.1 million for net financing activities in 2015 primarily due to the issuance of 5,700,000 shares of common stock largely offset by the repayment of credit facility borrowings. The Company used $670.3 million for net financing activities in 2014 largely due to the repayment of $600 million Senior Term Loans, discontinued operations primarily related to the sale of Alagasco and the purchase and retirement of shares. In 2013, the Company provided $122.1 million from net financing activities primarily from the December 2013 issuance of $600 million of Senior Term Loans partially offset by the repayment of long-term debt of $350 million combined with a decrease in short-term borrowings. For each of the years, net cash provided by (used in) financing activities also reflected dividends paid to common shareholders and cash received from the issuance of common stock through the Company’s stock-based compensation plan.

Capital Expenditures
Capital spending at Energen is detailed below.

Years ended December 31, (in thousands)
2015
2014
2013
Property acquisitions
$
87,556

$
71,096

$
31,481

Development
370,331

406,597

654,222

Exploration
641,983

953,409

423,698

Other
14,938

20,849

11,352

Total
1,114,808

1,451,951

1,120,753

Less exploration expenditures charged to income
74,198

79,441

16,008

Net capital expenditures
$
1,040,610

$
1,372,510

$
1,104,745


FUTURE CAPITAL RESOURCES AND LIQUIDITY

Outlook
Realized commodity prices and production levels by commodity type are the two primary drivers of our liquidity. Recent price declines in the outlook for oil, natural gas liquids and natural gas indicate a significant risk for lower revenues and related operating cash flows. 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 2016 will help mitigate some of the commodity price volatility and recent declines; however, we currently have significantly fewer hedges in place for 2016 and at lower price levels than in 2015 and may not be able to execute new hedges at acceptable volumes or price levels. Unless commodity prices increase during 2016, we expect that the net prices we will receive for our 2016 production will decline relative to 2015. 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 2016 is estimated to range from 19.5 MMBOE to 20.3 MMBOE, with a midpoint of 19.9 MMBOE, including approximately 17.6 MMBOE of estimated production from proved reserves owned at December 31, 2015. Production estimates do not include amounts related to held for sale properties or 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.








37




Production volumes by commodity are expected to be as follows:

Year ended December 31, (MMBOE)
2016
Oil
12.6
Natural gas liquids
3.5
Natural gas
3.8
Total (midpoint of range)
19.9

During 2016, Energen expects an annualized decline rate of approximately 18.2 percent for its proved developed producing properties owned at December 31, 2015, excluding production from held for sale properties. During the same period, total production from proved properties is expected to decrease approximately 12.8 percent and total production is expected to decrease approximately 1.5 percent. The above proved developed producing properties decline rate is not necessarily indicative of Energen’s expectations for its terminal decline rate on a long-term basis.

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. Energen expects a compound annual decline rate for proved producing properties owned at December 31, 2015, excluding production from held for sale properties, for the 5 year period 2015 to 2020, for the 10 year period 2015 to 2025 and for the 20 year period 2015 to 2035 of approximately 16.2 percent, 12.5 percent and 10 percent, respectively.

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 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 2016, we expect our oil and natural gas capital spending to total approximately $250 million, including $209 million for existing properties and $36 million for exploration. Included in this $209 million is approximately $58 million for the development of previously identified proved undeveloped reserves. Capital spending is required to offset declines in production and proved oil and natural gas 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 challenging market for crude oil and natural gas.

Capital expenditures in the Permian Basin by area during 2016 are planned as follows:

Year ended December 31, (in thousands)
2016
Midland Basin
$
197

Delaware Basin
41

Other
3

Net Carry-in/Carry Out
5

Total
$
246


Energen anticipates having the following drilling rigs and net wells by area during 2016. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.

 
Drilling Rigs
Net Wells
Permian Basin
1-2
11


38




Included in Energen’s capital plan is approximately $168 million for the completion of 46 net drilled but uncompleted wells in the Midland Basin.

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.

Liquidity
At December 31, 2015, we had $1.3 million of cash on hand and $1.2 billion of committed financing available under our credit facilities. To finance our operations, working capital and capital spending, we expect to use internally generated cash flow from operations supplemented by our existing $1.4 billion five-year syndicated credit facility. In addition, we have classified our remaining San Juan Basin properties as held for sale as of December 31, 2015 and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale.

Energen may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Access to capital is an integral part of Energen’s business plan. As of December 31, 2015, the Company has $222.5 million outstanding under its revolving credit facilities and $554.0 million outstanding under long term note agreements. 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 and possible credit rating downgrades. To the extent current market conditions continue for a prolonged period or worsen, we may be forced to reduce or delay capital and operational expenditures, divest assets, seek additional debt or equity financing, or refinance all or a portion of our debt.

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. As of December 31, 2015, we were in compliance with our covenants and expect to maintain compliance during 2016 assuming we are able to execute on our business plan which includes property divestitures and/or access to the capital markets and utilization of our credit facility. However, 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, at future measurement dates in 2016 and beyond. Such factors may include further 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 2016. 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, during 2016. 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 credit facilities and long term note agreements, which is an aggregate balance outstanding of $776.5 million at December 31, 2015. 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.

On September 2, 2014, Energen entered into a five-year syndicated secured credit facility with domestic and foreign lenders. On October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.4 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other non-cash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0; 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; and, during certain periods, to maintain a ratio of the net present value of proved reserves of our oil and natural gas properties to consolidated total debt greater than or equal to 1.50 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 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. 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

39




redeterminations. Given the lower price environment since our prior redetermination, we would expect a reduction in our borrowing basis at the next scheduled redetermination. Our next scheduled redetermination is April 1, 2016.

At December 31, 2015, Energen reported negative working capital of $41.2 million arising from current liabilities of $287.5 million exceeding current assets of $246.3 million. Working capital at Energen is influenced by the fair value of derivative financial instruments associated with future production. Energen has $57.0 million in current assets and $0.5 million in current liabilities associated with its derivative financial instruments at December 31, 2015. Energen relies upon cash flows from operations supplemented by our credit facility to fund working capital needs.

Workforce Reduction
On January 22, 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 and current oil and natural gas commodity prices. In connection with the reduction, we will incur a total charge of approximately $3.2 million in the first quarter of 2016 for one-time termination benefits.

Credit Ratings
On February 11, 2016, Moody’s Investors Service lowered Energen’s Corporate Family rating from Ba1 to B1 with a negative outlook. Moody’s Senior Unsecured Medium-Term Notes and Senior Unsecured Regular Bond ratings were lowered from Ba2 to B3 with a negative outlook. On February 9, 2016, Standard and Poor’s affirmed its Corporate credit rating for Energen at BB with a stable outlook.
Equity Offering and Shares Issued
During the second quarter of 2015, Energen issued 5,700,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $398.6 million, after deducting offering expenses. Net proceeds from this offering were initially used to repay borrowings under our credit facility and for general corporate purposes.

(in thousands)
December 31, 2015
December 31, 2014
Shares outstanding
78,795

72,973

Treasury stock*
2,976

2,903

Shares issued
81,771

75,876

*Excludes 50,800 shares and 78,254 shares held in the 1997 Deferred Compensation Plan at December 31, 2015 and 2014, 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 2016. 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
In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 with the remainder to be paid in the first quarter of 2016. In connection with the termination of these plans, Energen has also classified approximately $3.3 million as of December 31, 2015 of its investment in a Rabbi Trust from other long term assets to prepayments and other assets in the accompanying balance sheets to reflect its intent to utilize these assets to partially fund the estimated payments in the first quarter of 2016.

In October 2014, Energen’s Board of Directors amended and restated the Employee Savings Plan to make certain benefit design changes effective January 1, 2015. The benefit design changes include an increase in the percentage of Company match and other contributions. In February 2016, Energen announced additional changes to benefits under the Employee Savings Plan, effective March 21, 2016, which reduces the percentage of Company match.




40




Stock Repurchase Authorization
From time to time, the Company may 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. For the year ended December 31, 2014, Energen repurchased and retired 226,839 shares for $14.9 million pursuant to our repurchase authorization. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2015 and 2013. As of December 31, 2015, 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 from time to time acquires shares in connection with participant elections under Energen’s stock compensation plans. For the years ended December 31, 2015, 2014 and 2013, Energen acquired 73,126 shares, 32,768 shares and 14,766 shares, respectively, in connection with its stock compensation plans.

Contractual Cash Obligations and Other Commitments
In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes Energen’s significant contractual cash obligations, other than hedging contracts, as of December 31, 2015:

 
 
Payments Due Before December 31,

(in thousands)

Total
2016

2017-2018

2019-2020
2021 and Thereafter
Long-term debt (1)
$
776,500

$

$
19,000

$
222,500

$
535,000

Interest payments on debt
229,457

33,261

64,538

58,848

72,810

Operating leases
10,079

2,537

5,111

2,431


Asset retirement obligations (2)
718,952

5,480

4,919

5,235

703,318

Nonqualified supplemental retirement plans
15,729

14,606

231

217

675

Total contractual cash obligations
$
1,750,717

$
55,884

$
93,799

$
289,231

$
1,311,803


(1) Long-term debt obligations include approximately $0.4 million of unamortized debt discounts as of December 31, 2015.

(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 5.8 MMBOE through October 2020.

The contractual obligations reported above exclude Energen’s liability of $11.2 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 that is now under appeal. In the Revised Order, ONRR has ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700. Energen estimates that application of

41




the Revised Order 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 continues to vigorously contest the Revised Order 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, 2015.

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

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 gain position with eleven of our active counterparties and in a net loss position with the remaining one at December 31, 2015. 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, 2015, Energen was in a net gain position of $56.5 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in an approximate $4.3 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 assets as of December 31, 2015 represent an immaterial amount of both total assets and 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 $0.1 million change in the fair value of open Level 3 derivative contracts and to the results of operations.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets. The Commodities Futures Trading Commission (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.  We believe Energen’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act swap clearing and exchange-trading requirements pursuant to final regulations adopted by the CFTC and SEC. However, the Dodd-Frank Act also authorized the CFTC to set position limits for certain futures and options contracts in the major energy markets and for swaps that are their economic equivalents. 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 subsequently proposed new position limits in November 2013. The CFTC has supplemented the new position limit rule proposal as recently as September 2015, and the final rules have not yet been adopted. The full impact of the Dodd-Frank Act and related regulatory requirements on Energen will not be known until the regulations have been fully implemented and the derivative markets have adjusted to such regulations. Energen could experience increased costs and reduced liquidity in the markets as a result of these rules and regulations governing derivatives, which could reduce hedging opportunities and negatively affect our revenues and cash flows.

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

42




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, 2015. The independent reservoir engineers have issued reports covering approximately 99 percent of the Company’s ending proved reserves and in their judgment these estimates were reasonable in the aggregate. Energen’s production of proved undeveloped reserves requires the drilling of development wells and the installation or completion of related infrastructure facilities.

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

The table below reflects an estimated increase in 2016 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and natural gas reserve amounts at December 31, 2015:

 
Percentage Change in Proved Oil & Natural Gas Reserves From Reported Reserves
 
as of December 31, 2015
(dollars in thousands)
-5%
-10%
Estimated increase in DD&A expense for the
year ended December 31, 2016, net of tax
$
14,416

$
30,322


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.


43




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 2015 as discussed under Asset Impairment in our Results of Operations. A further decline in our price assumptions by 10 percent (assuming all other assumptions are held constant) would result in approximately $240 million of impairment expense on properties, primarily in the Central Basin Platform, not impaired at December 31, 2015. No additional expense would be recognized on properties previously impaired. Other assumptions such as operating costs, transportation costs, well and reservoir performance, severance 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. We enter into derivative transactions that are accounted for as mark-to-market transactions with gains and losses reported in current period gain (loss) on derivative instruments, net. Energen does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.

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

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD

See Note 19, Recently Issued Accounting Standards, in the Notes to Financial Statements for information regarding recently issued accounting standards.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained herein should be read in conjunction with the related disclosures as set forth 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 seasonal weather patterns, world and national supply-and-demand factors 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  2015, our average realized oil prices fell 46.2 percent to $45.04 per barrel, average realized natural gas liquids prices decreased 54.7 percent to an average price of $0.29 per gallon and average realized natural gas prices decreased 44.4 percent to $2.32 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, 2015, Energen entered into the following transactions for 2016 and subsequent years:

Production Period
Total Hedged Volumes
Average Contract
Price

Description
Fair Value (in thousands)
Oil
 
2016
1,086
 MBbl
$63.80 Bbl
NYMEX Swaps
$
24,126

Oil Basis Differential
 
2016
7,524
 MBbl
$(1.92) Bbl
WTI/WTI Basis Swaps
(13,180
)
2016
2,117
 MBbl
$(1.63) Bbl
WTS/WTI Basis Swaps
(2,878
)
December 2015 contracts (closed but not cash settled)
 
48,436

Total
 
 
 
$
56,504

WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
 
WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
 

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

Additionally, we have entered into certain sales volume and supply target arrangements with certain customers. A failure to meet sales volume targets at Energen due to miscalculations, weather events, natural disasters, accidents, mechanical failures, criminal acts or otherwise could leave us exposed to our counterparties in commodity hedging contracts and result in material adverse financial losses.

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

45




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, 2015 primarily relates to our syndicated credit facility with variable interest rates. The weighted average interest rate for amounts outstanding at December 31, 2015 was 1.64 percent. A 1 percent increase or decrease in the weighted average interest rate would have resulted in an approximate $2.2 million change in interest expense on our outstanding credit facility balance of $222.5 million at December 31, 2015. All long-term debt obligations, other than our credit facility, were at fixed rates at December 31, 2015. At December 31, 2015, we had interest rate swap agreements with a notional value of $66.7 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 1.0425 percent. The fair value of our interest rate swaps was a $0.2 million liability at December 31, 2015.


46




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, 2015 and 2014
 
 
 
 
Consolidated Statements of Income for the years ended December 31, 2015, 2014
and 2013
 
 
 
 
Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014
and 2013
 
 
 
 
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2015, 2014
and 2013
 
 
 
 
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013
 
 
 
 
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.


47



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Energen Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these 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 these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.

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 16, 2016


48




ENERGEN CORPORATION
CONSOLIDATED BALANCE SHEETS

(in thousands)
December 31, 2015
 
December 31, 2014
 
 
 
 
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
1,272

 
$
1,852

Accounts receivable, net
63,097

 
157,678

Inventories
11,255

 
14,251

Assets held for sale
93,739

 
395,797

Derivative instruments
56,963

 
322,337

Prepayments and other
20,014

 
27,445

Total current assets
246,340

 
919,360

Property, Plant and Equipment
 
 
 
Oil and natural gas properties, successful efforts method
 
 
 
Proved properties
7,611,118

 
6,903,514

Unproved properties
145,724

 
142,340

Less accumulated depreciation, depletion and amortization
3,454,510

 
1,893,106

Oil and natural gas properties, net
4,302,332

 
5,152,748

Other property and equipment, net
48,358

 
46,389

Total property, plant and equipment, net
4,350,690

 
5,199,137

Other postretirement assets
3,881

 

Other assets
12,782

 
19,761

TOTAL ASSETS
$
4,613,693

 
$
6,138,258


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


49




ENERGEN CORPORATION
CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)
December 31, 2015
 
December 31, 2014
 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
64,742

 
$
101,453

Accrued taxes
5,801

 
5,530

Accrued wages and benefits
28,563

 
21,553

Accrued capital costs
79,206

 
207,461

Revenue and royalty payable
60,493

 
72,047

Liabilities related to assets held for sale
12,789

 
24,230

Pension liabilities
15,685

 
24,609

Deferred income taxes


79,164

Derivative instruments
459

 
988

Other
19,783

 
23,288

Total current liabilities
287,521

 
560,323

Long-term debt
776,087

 
1,038,563

Asset retirement obligations
89,990

 
94,060

Pension and other postretirement liabilities

 
15,935

Deferred income taxes
552,369

 
1,000,486

Other
11,866

 
14,287

Total liabilities
1,717,833

 
2,723,654

Commitments and Contingencies


 


Shareholders’ Equity
Preferred stock, cumulative, $0.01 par value, 5,000,000
shares authorized

 

Common shareholders’ equity
 
 
 
Common stock, $0.01 par value; 150,000,000 shares authorized; 81,770,161 shares issued at December 31, 2015 and 75,875,711 shares issued at December 31, 2014
818

 
759

   Premium on capital stock
979,030

 
564,438

   Retained earnings
2,046,016

 
2,997,821