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.

Aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2015: $5,283,012,3512016: $4,616,230,556

Number of shares outstanding of the registrant’s common stock as of February 5, 2016: 78,791,45114, 2017: 97,187,767 shares

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:

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.

ITEM 1.    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 in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Headquartered in Birmingham, Alabama, ourgas. Our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources). At December 31, 2015, our remaining San Juan and primarily occur within the Midland 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.and the Central Basin Platform areas of the Permian Basin in west Texas and New Mexico. Our corporate headquarters are located in Birmingham, Alabama.

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 and Discontinued Operations, 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.

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;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.

Our revenues, cash flows and earnings are influenced predominantly by the amount of oil, natural gas liquids and natural gas we produce, net of the effects of settlements on our derivative commodity instruments, and the prices we receive for production. Oil, natural gas liquids and natural gas are commodities and theirhistorical markets for oil, natural gas liquids and natural gas have been volatile and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, during the year ended December 31, 2015,2016, commodity prices changed significantly, with the settlement price for West Texas Intermediate (WTI) crude oil ranging from a high of approximately $61.43$54.06 per barrel to a low of approximately $34.73$26.21 per barrel and settlement prices for Henry Hub natural gas ranging from a high of approximately $3.23$3.93 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$1.64 per Mcf.

Approximately 5963 percent of our December 31, 20152016 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:

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:

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.

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 20162017 and future years.

At December 31, 2015, approximately 95 percent and 5 percent2016, primarily all 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.Mexico. As a result of this geographic concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by:

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

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, adverse changes in the current commodity price environment andor industry 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,April 13, 2016, the borrowing base and aggregate commitments were reduced to $1.4 billion from $1.6$1.05 billion in association with the semi-annual redetermination required under the agreement. On October 25, 2016, the borrowing base was reaffirmed with no changes. As of December 31, 2015,2016, the Company had $222.5 millionno outstanding amounts 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, 2015,2016, we were in compliance with our covenants.covenants and expect to maintain compliance during 2017. However, in future periods, factors including those outside of our control may prevent us from maintaining compliance with the financial and non-financial covenants, including our total debt to EBITDAX covenant, at future measurement dates in 2016 and beyond.covenant. 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.appropriate. However, no assurances can be given with respect to such relief. If any such covenant violations are not waived by the lenders such violation would result in an event of default that could trigger acceleration of payment of the amounts outstanding under our credit facility and long term note agreements, which is an aggregate balance outstanding of $776.5 million at December 31, 2015.agreements. Additionally, the lenders could refuse to make additional loans under the credit facility, take possession of any collateral, and exercise other remedies or rights that may be available to them, all of which could have a material adverse effect on the business and financial condition of the Company. As more fully disclosed in 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”“Credit Facility and Working Capital”, the Company discusses its plans regarding liquidity and covenant compliance for 2016.2017.

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

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.

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.

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.

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.

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 isare insufficient to fully recover the cost invested in the respective project, we will record an impairment loss in our statements of income. We recorded $220.7 million and $1.3 billion of impairments during 2016 and 2015, and, if the depressed commodity price environment continues, we may be required to record additional impairments during 2016.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 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.

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

The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders and Energen. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition transactions involving Energen may negatively impact market and rating agency considerations regarding the credit of Energen, and management periodically considers these types of transactions.Energen.

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

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.

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

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 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.

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.

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 a district officesoffice in Midland, Texas and Farmington, New Mexico.Texas.

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

*All remaining San Juan Basin assets were classified as held for sale as ofsold during the year ended December 31, 2015.2016.

The following table sets forth proved reserves by area as of December 31, 2015:2016:

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, 2016, 2015 2014 and 20132014 of oil, natural gas liquids and natural gas.

The following table sets forth proved developed reserves by area as of December 31, 2015:2016:

The following table sets forth proved undeveloped reserves by area as of December 31, 2015:2016:

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

Proved undeveloped reserves transferred to proved developed reserves reflect capital expenditures of approximately $232$47 million during the year ended December 31, 20152016 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, 8.2include 22.9 MMBOE of proved undeveloped reserves that are now expectedwill no longer be developed in

the five-year time horizon due to be drilled after the original five year perioddevelopment being delayed to focus on other assets with higher returns, 1.1 MMBOE related to changes in year-end pricing, and 3.333.3 MMBOE of Wolfcampproved undeveloped reserves due to interference caused bythat were included in the sale of our wellbore placement geometry.non-core acreage. Positive revisions total 7.6 MMBOE, including 7.4 MMBOE from extending lateral length of certain locations.

Estimated proved reserves as of December 31, 20152016 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’sResources’ 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 Statestate 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 2015,2016, 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 statethe significant states in which Energen has wells:

The following table sets forth the total net productive oil and natural gas wells by area as of December 31, 2015,2016, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

The following table sets forth expiration dates for gross and net undeveloped acreage at year end as of December 31, 2015:2016:

*Other includes a total of 14,69414,591 gross (6,576(6,524 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, 2015,2016, Energen had approximately 354.7316.3 MMBOE total proved reserves which included 170.7154.2 MMBOE of proved undeveloped reserves. We had approximately 24.728.5 MMBOE or 14.418.5 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 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.

None

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On January 25, 2016,At February 13, 2017, there were 4,3834,114 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 2016.2017. 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:

**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.