UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 20142016

or

For the transition period from                      to                     

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

(713) 626-8525

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

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  ¨☐    No   þ☑

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  ¨☐    No  þ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ☑    No  ¨☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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  þ☑    No  ¨☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ☑

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

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $571,144,000$81,638,000 based on the closing sale price of $16.37$2.32 per share as reported by the New York Stock Exchange on June 30, 2014.2016.

The number of shares of the registrant’s common stock outstanding on March 3, 2015February 28, 2017 was 75,899,415.137,674,372.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders, to be filed within 120 days of the end of the fiscal year covered by this report, are incorporated by reference into Part III of this Form 10-K.

W&T OFFSHORE, INC.

TABLE OF CONTENTS

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  These forward-looking statements involve risks, uncertainties and assumptions.  If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.  All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future.  These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances.  Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of this Annual Report on Form 10-K and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission (“SEC”).  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law.  Unless the context requires otherwise, references in this Annual Report on Form 10-K to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

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PARTPART I

Item 1. Business

W&T Offshore, Inc. is an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties primarily in the Gulf of Mexico and the Permian Basin in West Texas.Mexico.  W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in 1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. and our wholly-ownwholly-owned subsidiary, W & T Energy VI, LLC, a Delaware limited liability company.    

The Gulf of Mexico is an area where we have developed significant technical expertise and where high production rates associated with hydrocarbon deposits have historically provided us the best opportunity to achieve a rapid return on our invested capital.  We have leveraged our historic experience in the conventional shelf (water depths of less than 500 feet) to develop higher impact capital projects in the Gulf of Mexico in both the deepwater (water depths in excess of 500 feet) and the deep shelf (well depths in excess of 15,000 feet and water depths of less than 500 feet).  We have acquired rights to explore and develop new prospects and acquired existing oil and natural gas properties in both the deepwater and the deep shelf, while at the same time continuing our focus on the conventional shelf.  Over the last several years, we have shiftedincreased our focus more toward the deepwater and to onshore in the Permian Basin of West Texas.  In the deepwater, we have completed numerous acquisitions and drilled both exploration and development wells.  Ouractivities in the deepwater, acreagewhich has expanded considerably and currently represents almost halfled to a greater percentage of our offshore acreage on a gross acreage basis.

Our onshore activities have been primarily in the Permian Basin in West Texas, where most of our leasehold interests were acquired in a single 2011 acquisition.  During 2014, we reassigned most of our interest in East Texas acreage acquired in 2011 back to the original assignor and currently have limited leasehold interest in East Texas and Louisiana.  total production coming from deepwater wells.

As of December 31, 2014,2016, we have interests in offshore leases covering approximately 1.1 million750,000 gross acres (0.7 million(450,000 net acres) spanning across the outer continental shelfOuter Continental Shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama.  On a gross acreage basis, the conventional shelf constitutes approximately 52%490,000 gross acres and deepwater constitutes approximately 48%260,000 gross acres of our offshore acreage.  Onshore, we have leasehold interests in approximately 50,000 gross acres (40,000 net acres), substantially all of which are in Texas. Approximately 58% of our total net offshore acreage is developed, and approximately 62% of our total net onshore acreage is developed.

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultants, our total proved reserves at December 31, 20142016 were 120.074.0 million barrels of oil equivalent (“MMBoe”) or 720.0444.0 billion cubic feet of gas equivalent (“Bcfe”).  Approximately 57%64% of our proved reserves as of such date were classified as proved developed producing, 12%23% as proved developed non-producing and 31%13% as proved undeveloped.  Classified by product, our proved reserves at December 31, 20142016 were 52%44% crude oil, 13%11% natural gas liquids (“NGLs”) and 35%45% natural gas.  These percentages were determined using the energy-equivalent ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs.  This energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly.  Our total proved reserves had an estimated present value of future net revenues discounted at 10% (“PV-10”) of $2.6 billion.$755 million before consideration of cash outflows related to asset retirement obligations (“ARO”).  Our PV-10 after considering future cash outflows related to asset retirement obligations (“ARO”) and without deducting future income taxesARO was $2.3 billion,$478 million, and our standardized measure of discounted future cash flows was $1.7 billionalso $478 million as of December 31, 2014.2016, as no future income taxes were estimated to be paid due to our current tax position.  Neither PV-10 nor PV-10 after ARO is a financial measure defined under generally accepted accounting principles (“GAAP”).  For additional information about our proved reserves and a reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows, see Properties – Proved ReserveReserves under Part I, Item 2 in this Form 10-K.

We seek to increase our reserves through acquisitions, exploratory and infill drilling, recompletions and workovers.  WeWith respect to acquisitions, we have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to add reserves, production and cash flow post-acquisition.  OurAlthough the current economic environment has caused us to take a conservative approach towards acquisitions, our acquisition team strivescontinues to findidentify and evaluate properties that will fit our profile and that we believe will add strategic and financial value to our company.Company.  During 2016 and 2015, we did not consummate any material acquisitions and we reduced our capital expenditures.  In 2015, we sold our interest in the Yellow Rose field discussed below.

In September 2016, we consummated a transaction whereby we exchanged approximately $710.2 million principal amount, or 79%, of our 8.500% Senior Notes due 2019 (the “Unsecured Senior Notes”) for $301.8 million principal amount of new secured notes and 60.4 million shares of our common stock.  In conjunction with the transaction, we closed on a new $75.0 million, 11.00%, 1.5 Lien Term Loan (the “1.5 Lien Term Loan”), and two amendments were made effective under our Fifth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”) (collectively, the “Exchange Transaction”).  See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7, and in Financial Statements and Supplementary Data– Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for a full description of the transaction, the new debt instruments and the accounting for the transaction.

From time to time, as part of our business strategy, we sell various properties.  In October 2015, we sold our ownership interests in the Yellow Rose onshore field to Ajax Resources, LLC (“Ajax”).  The field is located in the Permian Basin, West Texas, and covers approximately 25,800 net acres.  In addition to the cash purchase price, we were assigned a non-expense bearing overriding royalty interest (“ORRI”) equal to a variable percentage in production from the working interests assigned to Ajax, which percentage varies on a sliding scale from one percent for each month that the prompt month New York Mercantile Exchange (“NYMEX”) trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel.  Our internal estimate of the assigned proved reserves at the date of the sale to Ajax was 19.0 MMBoe, consisting of approximately 71% oil, 11% NGL and 18% natural gas.  In 2016 and 2014, we did not have any significant property sales.  

In September 2014, we acquired an additional ownership interest in the Mobile Bay blocks 113 and 132 located offshorein Alabama state waters (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively “Fairway”), which increased our ownership interest from 64.3% to 100%.  Internal estimates of additional proved reserves associated with the increased ownership interest in the Fairway Field as of the acquisition date were approximately 4.4 MMBoe (26.4 Bcfe), comprised of approximately 26% NGLs and 74% natural gas, all of which were classified as proved developed.

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In May 2014, we acquired from Woodside Energy (USA) Inc. (“Woodside”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Woodside Properties”).  The Woodside Properties consistedconsist of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks. Internal estimates

Under current commodity pricing conditions, we expect to continue to focus on conserving capital and maintaining liquidity.   We expect 2017 production to be slightly higher than 2016, but factors such as natural production declines, unplanned downtime and well performance could lead to lower production in 2017.  In addition, our capital expenditure plan for 2017 allocates approximately $125 million to projects in producing fields that we believe are low-risk and will provide a high rate of proved reserves associated withreturn.  While we will continue to evaluate opportunistic acquisitions, we expect that our acquisition activities may be reduced until the Woodside Properties as ofoutlook for the acquisition date were approximately 1.6 MMBoe (9.4 Bcfe), comprised of approximately 89% oil, 1% NGLs and 10% natural gas, all of which were classified as proved developed.

In November and December 2013, we acquired from Callon Petroleum Operating Company (“Callon”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Callon Properties”). The Callon Properties consist of a 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in associated production facilities and various interests in other non-operated fields. Internal estimates of proved reserves associated with the Callon Properties as of the acquisition dates were approximately 2.1 MMBoe (12.7 Bcfe), comprised of approximately 67% oil and 33% natural gas, all of which were classified as proved developed.

In October 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”), certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”). The Newfield Properties consisted of leases covering 78 federal offshore blocksfuture commodity pricing environment improves or unless financing is available on approximately 416,000 gross acres (268,000 net acres) predominantly in the deepwater. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 36% oil, 3% NGLs and 61% natural gas, all of which were classified as proved developed.

From time to time, as part ofreasonable terms that would not significantly impair our business strategy, we sell various properties. In 2014, we had no significant property sales.  In 2013, we sold our non-operated working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29, all located in the Gulf of Mexico. In 2012, we sold our non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico.available liquidity.

Additional information on these acquisitions and divestitures can be found under Properties in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7, and in Financial Statements and Supplementary Data - – Note 27 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K.

Our exploration efforts have historically been in areas in reasonably close proximity to known proved reserves, but starting in 2013,2012, some of our exploration projects were higher risk deepwater projects with potentially higher returns than our previous risk/reward profile. Historically, we have financed our drilling capital expenditures with operating cash flow.  The investment associated with drilling an offshore well and future development of an offshore project principally depends upon water depth, the depth of the well, the complexity of the geological formations involved and whether the well or project can be connected to existing infrastructure or will require additional investment in infrastructure.  Deepwater and deep shelf drilling projects can be substantially more capital intensive than those on the conventional shelf and onshore.shelf.  Certain risks are inherent in our business specifically and in the oil and natural gas industry generally, any one of which can negatively impact our rate of return on shareholders’ equityinvested capital if it occurs.  When projects are extremely capital intensive and involve substantial risk, we often seek participants to share the risk.  Onshore wells are less capital intensive than offshore wells, but the amount of reserves discovered and developed on a per well basis has historically been less from onshore wells than from offshore wells. We completed six,one, five and foursix offshore wells (gross) in 2016, 2015 and 33, 40 and 77 onshore wells (gross) in 2014, 2013 and 2012, respectively.

We generally sell our crude oil, NGLs and natural gas at the wellhead at current market prices or transport our production to “pooling points” where it is sold.  We are required to pay gathering and transportation costs with respect to a majority of our products.  Our products are marketed several different ways depending upon a number of factors including the availability of purchasers at the wellhead, the availability and cost of pipelines near the well or related production platforms, the availability of third-party processing capacity, market prices, pipeline constraints and operational flexibility.

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Our currentDue to the substantially lower commodity price environment experienced since the first half of 2014 and the outlook for the remainder of 2017, we have set our 2017 capital expenditure budget for 2015at $125 million.  Although this is $200an increase from the $49 million not including any potential acquisitions. This compares toof capital expenditures incurred in 2016, our current plan for 2017 is still a significant reduction from 2015 and 2014 investment levels of $231 million and $630 million, and $636 million for 2014 and 2013, respectively.  TheWe have flexibility in our 2017 capital expenditure budget for 2015 is significantly lower than recent annual expenditures primarily due to the dramatic decline in crude oil prices.  The 2015 budget is being allotted as follows: 38% for exploration, 61% for development and less than 1% for other items. Geographically, the budget is split 92% for offshore and 8% for onshore, with the substantial majority of offshore dedicated to the deepwater. Through February 2015,because we have not closed any acquisitions, but we continueno long term rig commitments and no current pressure from co-owners to evaluate and bid on opportunities as they arise. We anticipate funding our 2015 capital budget and any potential acquisitions with cash flow from operating activities, cash on hand and borrowings under our revolving bank credit facility. The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises.  Hence, our 2015 capital budget has been set with these premises in mind.  For the portiondrill or complete a well.  Some of our capital budget relatedexpenditures planned for 2017 are expected to drilling,impact production in 2017, while most are expected to impact production in 2018 and beyond.  We expect 2017 production to be slightly higher than 2016, but factors such as natural production declines, timing of well completions, unplanned downtime and well performance could lead to flat or even lower production in 2017.  In addition, our operating policy has beenplans include spending $78 million in 2017 for ARO, compared to fund these expenditures with cash flow provided by operations.$72 million spent on ARO in 2016.  We continue to closely monitor commoditycurrent and forecasted prices and may reviseto assess if changes are needed to our capital budget if conditions warrant. We strive to be as flexible as possible and believe this strategy holds the best promise for value creation and growth and managing the volatility inherent in our business.plans. See Risk Factors under Part I, Item 1A in this Form 10-K for additional information.

Business Strategy

Our business strategy is to acquire, explore and develop oil and natural gas reserves on the Outer Continental Shelf (“OCS”),OCS, the area of our historical success and technical expertise, which we believe has yieldedwill yield desirable rates of return commensurate with our perception of risks.  The rapid and extended decline in crude oil, NGLs and natural gas prices that occurredcommenced in the backsecond half of 2014 and continued into the first part of 2015 has created a great deal ofmore uncertainty about future exploration and development.  We believe this uncertainty will continue until such time asAlthough commodity prices stabilized at higher levels during the costssecond half of goods2016 compared to the first half of 2016, prices are still low from historical levels and services utilizedprice volatility occurring in supportthe last three years continues to affect our evaluation of explorationpotential returns and production become more closely aligned with prevailing commodity prices.risks of our drilling projects.  We also believe attractive acquisition opportunities will continue to become available in the Gulf of Mexico as the major integrated oil companies and other large independent oil and gas exploration and production companies continue to divest properties to focus on larger and more capital-intensive projects that better match their long-term strategic goals.  Because of ongoing market volatility, more specifically, the reduction in oil and natural gas prices occurring in the last six months,Also, we expect to find opportunities will arise as other less well-capitalized producers may seek to divest their properties both onshorefor short-term cash flow needs.   Our plans for the short-term include operating within cash flow, maintaining liquidity, meeting our financial obligations, and offshore.pursuing acquisitions meeting our criteria.

   Our business strategy may need to be significantly altered to comply with financial assurance requirements and other regulatory hurdles, which may have a material adverse impact on our liquidity.  See Risk Factors under Part I, Item 1A and Financial Statements and Supplementary Data – Note 19 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information on this significant risk to our business and recent events.    

We believe a portion of our Gulf of Mexico acreage has exploration potential below currently producing zones, including deep shelf reserves at subsurface depths greater than 15,000 feet.  Although the cost to drill deep shelf wells is usually significantly higher than shallower wells, the reserve targets are typically larger, and the use of existing infrastructure, when available, can increase the economic potential of these wells.

In addition to pursuing offshore  Pursuit of acquisition opportunities in the Gulf of Mexico will be dependent on a number of factors, including commodity prices, access to capital markets, financial assurance requirements, other regulatory challenges, possible debt covenant restrictions, ARO and onshore opportunities in Texas, when market conditions improve, weother cash needs of the business.  We plan to continue to evaluate other areas that could be compatible with our technical expertiseacquisition opportunities and could yield desirable rates of return commensurate with our perception of risks. We may acquire or expand our offshore and onshore holdings through exploration, development and acquisition activities if attractive opportunities arise.financing options.

We believe our business approach has contributed to our success and has positioned us to capitalize on new opportunities.  Historically, we have limited our annual capital spending for drilling activities to operating cash flow, and we have used capacity under our revolving bank credit facility and the capital markets for acquisitions, development and to balance working capital fluctuations.  The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises.

Competition

The oil and natural gas industry is highly competitive.  We currently operate in the Gulf of Mexico and onshore in Texas and compete for the acquisition of oil and natural gas properties primarily on the basis of price for such properties.  We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas concernscompanies and individual producers and operators.  Many of these competitors are large, well established companies that have financial and other resources substantially greater than ours.ours and greater ability to provide the extensive regulatory financial assurances required for offshore properties.  Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment.environment and to finance acquisitions without compromising our ability to continue as a going concern.  For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, see Risk Factors under Part I, Item 1A in this Form 10-K.

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Oil and Natural Gas Marketing and Delivery Commitments

We sell our crude oil, NGLs and natural gas to third-party customers.  We are not dependent upon, or contractually limited to, any one customer or small group of customers.  However, in 2014,2016, approximately 47%43% of our sales were to Shell Trading (US) Co. and 20% were to Vitol Inc., with no other customer comprisedcomprising greater than 10% of our sales.  See Financial Statements  and Supplementary Data – Note 1 – Significant Accounting Policies – Concentration of Credit Risk under Part II, Item 8 in this Form 10-K for additional information about our sales to customers.2016 revenues.  Due to the free trading nature of the oil and natural gas markets and because oil and natural gas are freely traded commodities with numerous purchasers in the Gulf of Mexico, and Texas, we do not believe the loss of a single customer or a few customers would materially affect our ability to sell our production.  We do not have any agreements which obligate us to deliver material quantities to third parties.

Regulation

General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulationregulations as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion.  Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members.  The Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) regulations, pursuant to the Outer Continental Shelf Lands Act (“OCSLA”), apply to our operations on Federal leases in the Gulf of Mexico.  

The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”).  In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993.  While salesSales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.prices.

In addition, theThe Federal Trade Commission, the FERC and the Commodity Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets.  These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets.  WithWe are required to observe the market-related regulations enforced by these agencies with regard to our physical sales of crude oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by theseundertake.  

These departments and agencies which holdhave substantial enforcement authority.authority and the ability to grant and suspend operations, and to levy substantial penalties for non-compliance.  Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.  See Risk Factors under Part I, Item 1A in this Form 10-K for certain risks related to these and other regulations.

Federal leases.  Most of our offshore operations are conducted on federal oil and natural gas leases.  These leases are awarded based on competitive bidding and contain relatively standardized terms.  These leases require compliance with BOEM, BSEE, and other government agency regulations and orders that are subject to interpretation and change.  The BOEM and BSEE also regulate the plugging and abandonment of wells located on the OCS and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines on the OCS (collectively, these activities are referred to as “decommissioning”).  

Decommissioning and financial assurance requirements.  The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.  In July 2016, the BOEM issued Notice to Lessees #2016-N01 (“NTL #2016-N01”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”).  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.  Under the new NTL, qualifying operators may self-insure for an amount up to 10% of their tangible net worth.  In addition, the NTL implements a phase-in period for establishing compliance with additional security obligations for certain categories of properties covered under the NTL, whereby a lessee may seek compliance with its additional security requirements under a “tailored plan” that is approved by the BOEM and would require securing phased in compliance in three approximately equal installments during a one-year period from the date of the BOEM approval of the tailored plan.  In January 2017, in a notice to stakeholders, the BOEM announced that it was extending the implementation timeline for providing financial assurance under NTL #2016-N01 by an additional six months (the “January 2017 Extension”).  However, the January 2017 Extension did not apply to “sole liability properties.”  “Sole liability properties” are leases, ROWs or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations.  In February 2017, the BOEM withdrew orders affecting “sole liability properties” issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.  The February 2017 notice stated that any implementation issues associated with those sole liability orders will be discussed as part of the ongoing, six-month interactive process BOEM had initiated to gather input on other components of NTL #2016-N01 pursuant to the January 2017 Extension.  However, the BOEM reserved the right to re-issue sole liability orders before the end of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning sole liabilities.  See Risk Factors under Part I, Item 1A, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for more discussion on decommissioning and financial assurance requirements.

Reporting of decommissioning expenditures.  During December 2015, the BSEE issued a final rule requiring lessees to submit summaries of actual expenditures for decommissioning of wells, platforms, and other facilities required under the BSEE’s existing regulations.  The BSEE has reported that it will use this summary information to better estimate future decommissioning costs, and the BOEM typically relies upon the BSEE’s estimates to set the amount of required bonds or other forms of financial security in order to minimize the government’s perceived risk of potential decommissioning liability.

“Unbundling.” The Office of Natural Resources Revenue (the “ONRR”) has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant utilized during that period.  

Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation.  The price and terms for access to pipeline transportation are subject to extensive regulation.  In recent years, theThe FERC has undertaken various initiatives to increase competition within the natural gas industry.  As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limitedallows non-pipeline natural gas sellers, including producers, fromto effectively competingcompete with interstate pipelines for sales to local distribution companies and large industrial and commercial customers.  The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies.  In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services.  The rates for such storage and transportation services are subject to FERC ratemaking authority, and FERC exercises its authority either by applying cost-of-service principles or granting market based rates.

Similarly, the natural gas pipeline industry may also beis subject to state regulations, which may change from time to time.  During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (“Competition Bill”) and H.B. 1920 (“LUG Bill”). The Competition Bill gives the Railroad Commission of Texas (“RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. The RRC was subject to a sunset review during 2013 and was authorized to operate for an additional four years.  Its next scheduled sunset review is in 2017.

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The Outer Continental Shelf Lands Act (“OCSLA”),OCSLA, which is administered by the Bureau of Ocean Energy Management (“BOEM”)BOEM and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service.  One of the FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the OCS market, to provide producers and shippers working in the OCS with greater assurance of open access service on pipelines located on the OCS, and to provide non-discriminatory rates and conditions of service on such pipelines.  On June 18, 2008, theThe BOEM issued a final rule, effective August 18, 2008 that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.

In December 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtu”) during a calendar year must annually report starting May 1, 2009, such sales and purchases to the FERC.FERC to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.  It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.  Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.  These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state legislatures, state commissions and the courts.  The natural gas industry historically has been very heavily regulated.  As a result, there is no assurance that the less stringent regulatory approach recently pursued by the FERC, Congress and Congressthe states will continue.

While the changes by these federal and state regulatorsregulations for the most part affect us only indirectly, they are intended to further enhance competition in natural gas markets.  We cannot predict what further action the FERC, the BOEM or state regulators will take on these matters; however, we do not believe that any such action taken will affect us differently, in any material way, than other natural gas producers with which we compete.

Oil and NGLs transportation rates.  Our sales of crude oil, condensate and NGLs are not currently regulated and are transacted at market prices.  In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act.  The price we receive from the sale of crude oil and NGLs is affected by the cost of transporting those products to market.  Interstate transportation rates for crude oil, NGLs and other products are regulated by the FERC.  In general, interstate crude oil, condensate and NGL pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. The FERC has established an indexing system for such transportation, which generally allows such pipelines to take an annual inflation-based rate increase.

In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.statutes and regulations.  As it relates to intrastate crude oil, condensate and natural gas liquidsNGL pipelines, state regulation is generally less rigorous than the federal regulation of interstate pipelines.  State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests, which are infrequent and are usually resolved informally.

We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquidsNGL pipelines will affect us in a way that materially differs from the way they affect other crude oil, condensate and natural gas liquidsNGL producers or marketers.

Regulation of oil and natural gas exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels.  Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled.  Many states also have statutes or regulations addressing conservation of oil and gas resources, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing of such wells.

Federal leases. Most of our offshore operations are conducted on federal oil and natural gas leases, which are administered by the BOEM pursuant to the OCSLA. These leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEM, Bureau of Safety and Environmental Enforcement (“BSEE”), and other government agency regulations and orders that are subject to interpretation and change. The BOEM and BSEE have promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines. See Risk Factors under Part I, Item 1A in this Form 10-K for more information on new regulations and interpretations.

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To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied.  The significant reductions in oil and natural gas pricing since the middle of 2014 may also adversely impact the BOEM’s financial assurance determinations with respect to the Company. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases.  In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements for companies operating in federal waters. If the BOEM were to increase its financial assurance requirements substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated.  Any such suspension or termination could materially adversely affect our financial condition and results of operations.  In addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and abandonment liabilities. According to federal regulations, the BOEM will waive its supplemental bonding requirements when a lessee or its guarantor can demonstrate the financial capability and reliability to meet these obligations.  We have demonstrated our financial capability and reliability to the satisfaction of the BOEM and the agency does not require that the Parent Company post any supplemental bonds to cover our operations on the OCS.

In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million relative to such underpayment.  We believe the fine is excessive and extreme considering the circumstances and in relation to the amount of underpayment.  On April 23, 2014, we filed a request for a hearing on the record and a general denial of the ONRR’s allegations contained in the notice.  We intend to contest the fine to the fullest extent possible. The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years.  As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of December 31, 2014 per authoritative guidance.  However, we cannot state with certainty that our estimate of the exposure is accurate concerning this matter.

Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS.  The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs.  The BOEM and the BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms.  In an effort to reduce the potential for future damage, the BOEM and the BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures.  It is possible that similar, if not more stringent, requirements will be issued by the BOEM and/or the BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs and/or capital expenditures.

Environmental Regulations

General. We are subject to complex and stringent federal, state and local environmental laws.  These laws, among other things, govern the issuance of permits to conduct exploration, drilling and producing operations, the amounts and types of materials that may be released into the environment, the discharge and disposal of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities.  Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with, and which carrya failure to comply may result in substantial administrative, civil and even criminal penalties for failure to comply.or the suspension or cessation of operations in affected areas.  Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person.  Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas.  In addition, state laws often require various forms of remedial action to prevent and address pollution, such as the closure of inactive oil and gas waste pits and the plugging of abandoned wells.  The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability.  The cost of remediation, reclamation and abandonment of wells, platforms and other facilities in the Gulf of Mexico may require us to incur significant costs.is significant.  These costs are considered a normal, recurring cost of our on-going operations.  Our domestic competitors are generally subject to the same laws and regulations.

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Hazardous Substances and Wastes.  The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment.  These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances.  Under CERCLA, such persons are subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies.  In addition, companies that incur liability frequently also confront third-party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.  Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.  In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”), regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites.  RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.waste,” Disposaland the disposal of such non-hazardous oil and natural gas exploration, development and production wastes is usually regulated by state law.  Other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, however, various environmental groups have challenged the Environmental Protection Agency’s (“EPA”) exemption of certain oil and gas wastes from RCRA.  For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016.  Under the decree, the EPA must propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary.  If the EPA proposes a rulemaking for revised oil and gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.  In addition, legislation is frequently proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,wastes.”  therebyA loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could potentially subjectingsubject such wastes to more stringent handling, disposal and cleanup requirements.  If such legislation were enacted, it could have a significant impactOther wastes handled at exploration and production sites or generated in the course of providing well services may not fall within the RCRA exclusion.  Moreover, stricter standards for waste handling and disposal may be imposed on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.the future.  Additionally, Naturally Occurring Radioactive Materials (“NORM”) may contaminate minerals extraction and processing equipment used in the oil and natural gas industry.  The waste resulting from such contamination is regulated by federal and state laws.  Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws.  We do not anticipate any material expenditures in connection with our compliance with RCRA and applicable state laws related to NORM waste.

Air Emissions and Climate Change.  Air emissions from our operations are subject to the Federal Clean Air Act (“CAA”) and comparable state and local requirements.  We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.  For example, the U.S. Environmental Protection Agency (“EPA”) has established air emission controls requirements for oil and natural gas production and natural gas processing operations.  Specifically, the EPA established New Source Performance Standards for emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards for hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA rules require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent any hydrocarbons that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants. These rules may require a numberEPA has developed, and continues to develop, stringent regulations governing emissions of modifications to our operations includingtoxic air pollutants at specified sources.   Moreover, the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results. However, we believe our operations will not be materially adversely affected by any such requirements,U.S. Congress and the requirements are not expectedEPA, in addition to be any more burdensomesome state and regional efforts, have in recent years considered legislation or regulations to us than to other similarly situated companies involved in oilreduce emissions of greenhouse gases.  These efforts have included consideration of cap-and-trade programs, carbon taxes, and naturalgreenhouse gas explorationmonitoring and production activities.

Climate Change. Thereporting programs.  In the absence of federal greenhouse gas limitations, the EPA has determined that greenhouse gas emissions of carbon dioxide, methane and other “greenhouse gases” present an endangermenta danger to public health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and it has adopted regulations that, among other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations tothings, restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA has adopted two setsCAA and may require the installation of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction incontrol technologies to limit emissions of greenhouse gases.  For example, in June 2016, the EPA published new source performance standards that require new, modified, or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile organic compound emissions.  These regulations would apply to any new or significantly modified facilities that we construct in the future that would otherwise emit large volumes of greenhouse gases from motor vehiclestogether with other criteria pollutants.  Also, certain of our operations are subject to EPA rules requiring the monitoring and the other of which requires preconstruction and operating permits for certain large stationary sources. The EPA also requires theannual reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gasoffshore production facilities, on an annual basis. We believe we are in compliance withsources.  See Risk Factors under Part I, Item 1A of this new emission reporting requirement as it applies to our operations.  Form 10-K for further discussion.

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In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Water Discharges.  The primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”) which amends and augments oil spill provisions of the federal Water Pollution Control Act (the “Clean Water Act”).  OPA imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters, including the OCS or adjoining shorelines.  A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located.  OPA assigns joint and several, strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil and natural resource damages and economic damages suffered by persons adversely affected by an oil spill.  Although defenses exist to the liability imposed by OPA, they are limited.  In addition, in December 2014, the BOEM issued a final rule, effective January 12, 2015, which raiseshas raised OPA’s damages liability cap from $75 million to $133.65$134 million.  OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill, and to prepare and submit for approval oil spill response plans.  These oil spill response plans must detail the action to be taken in the event of a spill; identify contracted spill response equipment, materials, and trained personnel; and identify the time necessary to deploy these resources in the event of a spill.  In addition, OPA currently requires a minimum financial responsibility demonstration of between $35 million and $150 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to a maximum of $150 million.OCS.  We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS.  As a result of the BP Deepwater Horizon incident, legislation has been proposed in Congress to increase the minimum level of financial responsibility to $300 million or more. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the monitoring and discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state.  The EPA has also adopted regulations requiring certain onshore oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.  Costs may be associated with theThe treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our onshore facilities.gas processing plant may have significant costs.  Obtaining permits has the potential to delay the development of oil and natural gas projects.  These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs.  Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil.  We currently maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

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Hydraulic Fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppants and chemicals under pressure into the formation to fracture the rock formation and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (the “SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities in February 2014. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources.  We follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities including disclosure requirements. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells that require hydraulic fracturing.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA is performing a study of the potential environmental effects of hydraulic fracturing on drinking water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report in 2015. The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards in 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

Protected and Endangered Species.  Executive Order 13158, issued in May 2000, directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”) in the United States and establish new MPAs.  The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable.  It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment.  This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.

In addition, Federal Lease Stipulations include regulations regarding the taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species).  The BSEE also issues numerous regulations under the nomenclature Notice to Lessees (“NTL”) that provide formal guidelines on implementation of OCS regulations and standards. We believe we are in compliance in all material respects with the requirements regarding protection of marine species.

Certain flora and fauna that have been officially classified as “threatened” or “endangered” are protected by the Endangered Species Act.Act (“ESA”).  This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area.  IfWe conduct operations on leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species are located in an area where we wish to conduct seismic surveys, development or abandonment operations, the workthat potentially could be prohibitedlisted as threatened or delayed or expensive mitigation could be required.

endangered under the ESA may exist.  We own a non-producing platform in the Gulf of Mexico located in a National Marine Sanctuary.  As a result, we are subject to additional federal regulation, including regulations issued by the National Oceanic and Atmospheric Administration.  Unique regulations related to operations in a sanctuary include prohibition of drilling activities within certain protected areas, restrictions on the types of water and other substances that may be discharged, required depths of discharge in connection with drilling and production activities and limitations on mooring of vessels.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief.

Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Magnuson-Stevens Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.  These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands.  These and other protected areas may require certain mitigation measures to avoid harm to wildlife, and such laws and regulations may impose substantial liabilities for pollution resulting from our operations.  The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.

9Financial Information

We maintain liability insurance and well control insurance for all ofoperate our operations. In addition, we maintain property and hurricane damage insurance coverage for some, but not all, of our properties, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain does not cover the risks described above from gradual pollution events which occur overbusiness as a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover such risks or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant environmental event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.single segment. See Management’s Discussion and Analysis ofSelected Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claims and Insurance CoverageData under Part II, Item 76 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for additional information on insurance coverage.our financial information.

Seasonality

For a discussion of seasonal changes that affect our business, see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Inflation and Seasonality under Part II, Item 7 in this Form 10-K.

Employees

As of December 31, 2014,2016, we employed 339302 people.  We are not a party to any collective bargaining agreements and we have not experienced any strikes or work stoppages.  We consider our relations with our employees to be good.

Additional Information

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, other reports and otheramendments to those reports with the SEC.  Our reports filed with the SEC are available free of charge to the general public through our website at www.wtoffshore.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC.  This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., Nine Greenway Plaza, Suite 300, Houston, Texas 77046 or by calling (713) 297-8024.  These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549.  The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.  Information on our website is not a part of this Form 10-K.

Item 1A. Risk Factors

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to us and our industry could materially impact our future performance and results of operations.  We have provided below a list of known material risk factors that should be reviewed when considering buying or selling our securities.  These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.

Risks Relating to the Oil and Natural GasOur Industry, Our Business and Our BusinessFinancial Condition

Substantial or extendedFurther declines in crude oil, NGLs and natural gas prices mayor an extended period of currently depressed prices will adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our future capital expenditure obligations and financial commitments and to implement our business strategy.

The price we receive for our crude oil, NGLs and natural gas production directly affects our revenues, profitability, access to capital and future rate of growth.  Oil,Crude oil, NGLs and natural gas are commodities and are subject to wide price fluctuations in response to relatively minor changes in supply and demand.  LowerThe significantly reduced prices for our crude oil, NGLs and natural gas production may not only decreasein 2016 and 2015 have substantially decreased our revenues on a per unit basis but mayand have also reducereduced the amount of crude oil, NGLs and natural gas that we can produce economically.  Historically, the markets for crude oil, NGLs and natural gas have been volatile and will likely continue to be volatile in the future.  The prices we receive for our production and the volume of our production depend on numerous factors beyond our control.  These factors include the following:

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The prices of crude oil, domestic natural gas and NGLs have declined substantially since Junestarting in the second half of 2014.  The average price per barrel of West Texas Intermediate (“WTI”) crude oil has decreased from $107was over $90.00 in 2014, approximately $49.00 in 2015 and approximately $43.00 per barrel in the middle of June 2014 to as low as $44 per barrel in January 2015.2016.  This decrease in prices has impacted all companies throughout the oil and gas producers to varying degrees depending on hedging strategies.industry.  Natural gas and NGLsNGL prices have also been negatively affected by excess natural gas production, high levels of stored natural gas and weather conditions affecting demand.  In recent months,During 2014, the average Henry Hub spot pricesprice for natural gas have declined to prices lower than $3.00was above $4.00 per McfMMBtu compared to average pricesapproximately $2.60 per MMBtu during 20142015 and approximately $2.50 per MMBtu in excess of $4.00 per Mcf. There have been significant recent development2016.  Development activities in shale and other resource plays which have the potential to yield a significant amount of natural gas and NGLs production, as well as natural gas and NGLs produced in connection with increased domestic oil drilling activities.  The potential increases in natural gas supplies resultingAlthough oil prices have increased somewhat from the large-scale developmentlows of these unconventional resource reserves could continuethe first quarter of 2016, margins are still low compared to have an adverse impact on the price of natural gas and NGLs.historical levels.  An environment of further or continued lowerlow crude oil, NGLs and natural gas prices would materially and adversely affect our future business, financial condition, results of operations, liquidity, and/or ability to finance planned capital expenditures.expenditures, ability to fund our ARO, ability to repay any borrowings per our debt agreements, to secure supplemental bonding, to secure collateral for such bonding, if required, and to meet our other financial obligations.

The borrowing base under our Credit Agreement may be reduced by our lenders.

IfAvailability of borrowings and letters of credit under the Credit Agreement is determined by establishment of a borrowing base, which is periodically redetermined during the year based on our lenders’ view of crude oil, NGLs and natural gas prices and on our proved reserves.  The borrowing base under the Credit Agreement was reduced during 2016, and was $150 million as of December 31, 2016 compared to $750 million as of December 31, 2014.  The lower borrowing base was primarily due to declines in commodity prices.  The borrowing base could be further reduced in the future as a result of the continued impact of low commodity prices, our lenders’ outlook for future prices or our inability to replace reserves as a result of constrained capital spending.  To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base; such excess or deficiency is required to be repaid within 90 days in three equal monthly payments.  In addition to the borrowing base limitation, the Credit Agreement limits our ability to incur additional indebtedness if we cannot comply with specified financial covenants and ratios.

We may not have the financial resources in the future to repay an excess or deficiency resulting from a borrowing base redetermination as required under our Credit Agreement, which could result in an event of default.  Additionally, a material reduction of our current cash position could substantially limit our ability to comply with other cash needs, such as collateral needs for existing or additional supplemental surety bonds or other financial assurances issued to BOEM for our decommissioning obligations.  Further, the failure to repay an excess or deficiency that may result from a borrowing base redetermination under our Credit Agreement may result in a cross-default under our other debt agreements.  Continued low crude oil, NGLs and natural gas prices in the future would continue to adversely affect our cash flow, which could result in further reductions in our borrowing base, adversely affect prospects for alternative credit availability or affect our ability to satisfy our covenants and ratios under our Credit Agreement.

We may be unable to provide the financial assurances demanded by the BOEM to cover our decommissioning obligations in the amounts and under the time periods required by the BOEM.  If extensions and modifications to the BOEM’s current or future demands are needed and cannot be obtained, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.  

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.  In July 2016, the BOEM issued NTL #2016-N01 to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs.  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.  In January 2017, the BOEM issued the January 2017 Extension for non-sole liability properties.  During 2016 and in January and February 2017, we received notices from the BOEM concerning financial assurances of our decommissioning obligations, which are summarized below.  

As suggested by the BOEM in its January and February notices to stakeholders, we intend to use the six month extension granted by the BOEM as an opportunity to propose and negotiate acceptable plans dealing with both sole and non-sole liability properties.

While we expect to be able address the financial assurances of our sole and non-sole liability properties in accordance with the guidelines under NTL #2016-N01, we cannot provide any assurance at this time on when the BOEM will direct that such financial assurance coverage must be submitted or how to structure such coverage, and if we are able to fund such coverage.  We could in the future receive further or revised demands from the BOEM for additional financial assurances covering our obligations under sole liability properties and/or our non-sole liability properties.  The BOEM may reject our proposals and make demands that exceed the Company’s capabilities.  

If we fail to comply with the current or future orders of the BOEM to provide additional surety bonds or other financial assurances, the BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.

We may be required to post cash collateral pursuant to our agreements with sureties under our existing bonding arrangements, which could have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our ARO plan and comply with our existing debt instruments.

Pursuant to the terms of our agreements with various sureties under our existing bonding arrangements or under any additional bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the surety’s discretion.  We have received such demands and have provided collateral to a couple of our existing sureties.  If additional collateral is required to support surety bond obligations, this collateral would probably be in the form of cash or letters of credit.  Given current commodity prices’ effect on our creditworthiness and the willingness of the surety to post bonds without the requisite collateral, we cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds.

If we are required to provide collateral, our liquidity position will be negatively impacted and may require us to seek alternative financing.  To the extent we are unable to secure adequate financing; we may be forced to reduce our capital expenditures in the current year and/or future years.  In addition, a reduction in our liquidity may impair our ability to comply with the financial and other restrictive covenants in our indebtedness.  Moreover, if we default on our Credit Agreement, then we would need a waiver or amendment from our bank lenders to prevent the acceleration of the outstanding debt under our Credit Agreement.  There is no assurance that the bank lenders will waive or amend the Credit Agreement.  Realization of any of these factors could have a material adverse effect on our financial condition, results of operations and cash flows.

We have a significant amount of indebtedness.  Our leverage and debt service obligations may have a material adverse effect on our financial condition, results of operations and business prospects, and we may have difficulty paying our debts as they become due.

As of December 31, 2016, we had approximately $1.0 billion recorded as debt, which includes $189.8 million principal amount of unsecured indebtedness and $683.9 million principal amount of secured indebtedness outstanding and less than $1 million in outstanding letters of credit.  Our current availability on our revolving bank credit facility is approximately $150 million and we had no borrowings outstanding on our revolving bank credit facility.  For example, our leverage could:

Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors.  We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation.  Substantially all of our oil, NGLs and natural gas properties are pledged as collateral under our Credit Agreement and also pledged as collateral on a subordinate basis under certain other debt agreements.  Sustained or lower crude oil, NGLs and natural gas prices in the future will continue to adversely affect our cash flow and could result in further reductions in our borrowing base, reduce prospects for alternate credit availability, and affect our ability to satisfy the covenants and ratios under our Credit Agreement.  Further asset sales may also reduce available collateral and availability under our Credit Agreement.  In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations.

If we are unable to service our indebtedness and other obligations, we may be required to further restructure or refinance all or part of our existing debt, sell assets, reduce capital expenditures, borrow more money or raise equity.  We may not be able to further restructure or refinance our debt, reduce capital expenditures, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness.  In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness is uncertain and will be affected by our future performance and events or circumstances beyond our control.  Failure to comply with these covenants would result in an event of default under such indebtedness, the potential acceleration of our obligation to repay outstanding debt and the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness.  Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations and could lead to a restructuring.

We may be able to incur substantially more debt. This could exacerbate the risks associated with our indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to the terms of our debt agreements. As of December 31, 2016, we had $189.8 million of unsecured indebtedness and approximately $683.9 million of secured indebtedness outstanding (excluding $0.5 million of letters of credit and amounts included in the carrying value of certain debt for future payment-in-kind (“PIK”) and cash interest payments).  The components of our indebtedness are:

If new debt is added to our current debt levels, the related risks that we and our subsidiaries face could intensify. Our level of indebtedness may prevent us from engaging in certain transactions that might otherwise be beneficial to us by limiting our ability to obtain additional financing, limiting our flexibility in operating our business or otherwise.  In addition, we could be at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their business.

Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.

The indentures and credit agreements governing our indebtedness contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt.  These covenants limit our ability and the ability of our restricted subsidiaries, among other things, to:

Our revolving bank credit facility requires us, among other things, to maintain certain financial ratios and satisfy certain financial condition tests or reduce our debt.  These restrictions may also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities.  We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us from the restrictive covenants under our indentures governing our other debt instruments.

A breach of any covenant in the agreements governing our debt would result in a default under such agreement after any applicable grace periods.  A default, if not waived, could result in acceleration of the debt outstanding under such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements.  The accelerated debt would become immediately due and payable.  If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt.  Even if new financing were then available, it may not be on terms that are acceptable to us.

We may not be able to extend, renew, refund, defease, discharge, replace or refinance our Unsecured Senior Notes by February 28, 2019.  

The maturity of the Third Lien PIK Toggle Notes and the 1.5 Lien Term Loan will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes are not extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Assuming the PIK option is fully utilized for the Third Lien PIK Toggle Notes; the principal balance would grow and would be approximately $172.7 million as of February 28, 2019.  For the 1.5 Lien Term Loan, no PIK option is available and the principal of $75.0 million would be unchanged as of February 28, 2019.  Thus, a total of $247.7 million may become due on February 28, 2019.   We may not have available funds to make these payments, which may cause us to be in default if we are unable to refinance the Unsecured Senior Notes before then.  A default, if not waived, could result in acceleration of the debt outstanding under such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements.  The accelerated debt would become immediately due and payable.  If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt.  Even if new financing were then available, it may not be on terms that are acceptable to us.

We may be unable to access the equity or debt capital markets to meet our obligations.  

Sustained or lower crude oil, NGLs and natural gas prices will adversely affect our cash flow and may lead to further reductions in the borrowing base, which could also lead to reduced prospects for alternate credit availability.  The capital markets we have historically accessed as an alternative source of equity and debt capital are currently very constrained.  Other capital sources may arise with significantly different terms and conditions.  These limitations in the capital markets may affect our ability to grow and limit our ability to replace our reserves of oil and gas.

Our plans for growth may include accessing the capital and credit markets.  If the debt or equity capital markets do not improve, or if we are unable to access alternative means of financing on acceptable terms, we may be unable to implement all of our drilling and development plans, make acquisitions or otherwise carry out our business strategy, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

If we default on our secured debt, the value of the collateral securing our secured debt may not be sufficient to ensure repayment of all of such debt.

As of December 31, 2016, we had secured debt outstanding of $836.7 million which includes the outstanding principal, PIK and accrued interest and certain letter of credit reimbursement obligations.  If in the future we default on one or more issues or tranches of our secured debt, we cannot assure you that the proceeds from the sale of the collateral will be sufficient to repay all of our secured debt in full.  In addition, we have certain rights to issue or incur additional secured debt, including up to $149.5 million as of December 31, 2016, available for borrowing on our revolving bank credit facility, that would be secured by additional liens on the collateral and an issuance or incurrence of such additional secured debt would dilute the value of the collateral securing our outstanding secured debt.  If the proceeds of any sale of the collateral are not sufficient to repay all amounts due in respect of our secured debt, then claims against our remaining assets to repay any amounts still outstanding under our secured obligations would be unsecured and our ability to pay our other unsecured obligations and any distributions in respect of our capital stock would be significantly impaired.

The collateral securing the various issues of our secured debt has not been appraised.  The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral.  The value of the assets pledged as collateral for our secured debt could be impaired in the future as a result of changing economic conditions, commodity prices, competition or other future trends.  Likewise, we cannot assure you that the pledged assets will be saleable or, if saleable, that there will not be substantial delays in their liquidation.

In addition, to the extent that third parties hold prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral securing our secured debt.

With respect to some of the collateral securing our secured debt, any collateral trustee’s security interest and ability to foreclose on the collateral will also be limited by the need to meet certain requirements, such as obtaining third party consents, paying court fees that may be based on the principal amount of the parity lien obligations and making additional filings.  If we are unable to obtain these consents, pay such fees or make these filings, the security interests may be invalid and the applicable holders and lenders will not be entitled to the collateral or any recovery with respect thereto.  We cannot assure you that any such required consents, fee payments or filings can be obtained on a timely basis or at all.  These requirements may limit the number of potential bidders for certain collateral in any foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral.  Therefore, the practical aspect of realizing value from the collateral may, without the appropriate consents, fees and filings, be limited.

If crude oil, NGLs and natural gas prices decrease from their current levels, or decrease further, we will likelymay be required to further write down the carrying values and/or the estimates of total reserves of our oil and natural gas properties.

Accounting rules applicable to us require that we periodically review the carrying value of our oil and natural gas properties quarterly for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we will likely be required to write down the carrying value of our oil and natural gas properties. Such write-downs constitute a non-cash charge to earnings.  Impairment of proved properties under our full cost oil and gas accounting method is largely driven by the present valuesvalue of future net revenues of proved reserves estimated using SEC mandated 12-month unweighted first-day-of-the-month commodity prices.  SinceIn addition to commodity prices, impairment assessments of proved properties include the evaluation of development plans, production data, economics and other factors.  As crude oil, natural gas and NGLs prices did not declinedeclined in 2014 until after June 2014, and more prominently2015, we incurred impairment charges in each quarter in 2015 totaling $987 million for the year.  Such write-downs constitute a non-cash charge to earnings.  As prices fell further during 2016, we incurred impairment charges in the fourth quarterfirst three quarters of 2014, the2016 which totaled $279 million.  If prices fall below levels received during 2016, this would impact of the recent pricing downturns will continue to adversely affect our SEC average pricing as recent and current prices roll into the SEC average prices used in evaluating impairment of our proved reserves under the full cost accounting “ceiling test”.   While we have not had any ceiling test impairments since 2009, sustained current prices or further declines in prices forestimated future revenues.  In addition, lower crude oil, NGLs and natural gas will likely result in future ceiling test impairments.  You should not assumeprices may reduce our estimates of the reserve volumes that may be economically recovered, which would reduce the $2.6 billion present value of future net revenues, PV-10, from our proved oil and natural gas reserves shown elsewhere in this document is the current markettotal value of our estimated oil and natural gasproved reserves.  (PV-10 is not a financial measure defined under GAAP.  For additional information about our proved reserves and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, see Properties – Proved Reserve under Part I, Item 2 in this Form 10-K.)  In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate.  Actual future prices and costs may differ materially from those used in the present value estimate.  For example, the average price used in the standardized measure of discounted cash flows for December 31, 2014 for crude oil was $91.12 per barrel and the average price of WTI crude oil in December 2014 was $59.29 per barrel.   

No assurance can be given that we will not experience additional ceiling test impairments in future periods, which could have a material adverse effect on our results of operations in the periods taken.  As a result of lower oil, NGLs and natural gas prices, we may also reduceAlso, no assurance can be given that commodity price decreases will not affect our estimates of the reserve volumes that may be economically recovered, which would reduce the total value of our proved reserves.volumes.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview and Critical Accounting Policies – Impairment of oil and natural gas properties under Part II, Item 7 and Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K for additional information on the ceiling test.

We may be limited in our ability to maintain proved undeveloped reserves under current SEC guidance.

Current SEC guidance requires proved undeveloped reserves (“PUDs”) may only be classified as such if a development plan has been adopted indicating that they are scheduledreasonably certain to be drilled within five years of the date of booking.  This rule may limit our potential to book additional proved undeveloped reservesPUDs as we pursue our drilling program.  If current low price conditions persist,prices decline, we also may be compelled to further postpone the drilling of proved undeveloped reservesPUDs until prices recover.  Further, ifIf we postpone drilling of proved undeveloped reservesPUDs beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped.  In addition, if we are unable to demonstrate funding sources for our development plan with reasonable certainty, we may have to write-off all or a portion of our PUDs.

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As of December 31, 2014, approximately 31%Our PUDs comprised 13% of our total proved reserves were undevelopedas of December 31, 2016 and approximately 12% of our total proved reserves were developed non-producing.  There can be no assurance that all of those reserves will ultimately be developed or produced.

Our undeveloped proved reserves and developed non-producing proved reserves require additional future expenditures and/or activities to convert these into producing reserves.  WeAs circumstances change, we cannot provide assurance thesethat all future expenditures will be made and that activities will be entirely successful in converting these reserves.  Additionally,Although we are the operator for all the fields containing our PUDs as of December 31, 2016, in the past, we were not the operator for approximately 17%a portion of our undeveloped proved reserves and approximately 11% of our proved developed non-producing reserves, so we may not bePUDs, which could have put us in a position of not being able to control the timing of all development activities.  Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reservesPUDs will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.

Relatively short production periods for our Gulf of Mexico properties subject us to high reserve replacement needs and require significant capital expenditures to replace our reserves at a faster rate than companies whose reserves have longer production periods.  Our failure to replace those reserves would result in decreasing reserves, production and cash flows over time.

Unless we conduct successful development and exploration activities at sufficient levels or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced.  Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors.  High production rates generally result in recovery of a relatively higher percentage of reserves during the initial few years of production.  The majorityAll of our current production is from the Gulf of Mexico.  Reserves in the Gulf of Mexico generally decline more rapidly than from reserves in many other producing regions of the United States.  Our independent petroleum consultant estimates that 42%55% of our total proved reserves will be depleted within three years.  As a result, our need to replace reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their reserves over a similar time period, such as those producers who have a larger portion of their reserves in areas other than the Gulf of Mexico.  We may not be able to develop, find or acquire additional reserves in sufficient quantities to sustain our current production levels or to grow production beyond current levels.  In addition, due to the significant time requirements involved with exploration and development activities, particularly for wells in the deepwater or wells not located near existing infrastructure, actual oil and natural gas production from new wells may not occur, if at all, for a considerable period of time following the commencement of any particular project.

Significant capital expenditures are required to replace our reserves.  If we are not able to replace reserves, we will not be able to sustain production at current levels.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable.  Unless we replace the reserves we produce through successful exploration, development or acquisition activities, our proved reserves and production will decline over time.  Our exploration, development and acquisition activities require substantial capital expenditures.  Historically, we have funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, securities offerings and bank borrowings.  The capital markets we have historically accessed are currently constrained butand we believe we couldour access otherto capital markets if the need arises. These limitations in the capital markets may affectremains limited at this time.  Compared to prior years, we significantly reduced our ability to grow and changes in our capitalization structure may significantly affect our financial risk profile.  Furthermore, we cannot be certain that financing for future capital expenditures will be available if needed,in 2016 and continue to have a low capital expenditure budget for 2017 in order to conserve capital and target projects with the extent required, onhighest probability of acceptable terms. For additional financing risks, see “– Risks Related to Financings.”

returns.  Future cash flows are subject to a number of variables, such as the level of production from existing wells, the prices of oil, NGLs and natural gas, and our success in developing and producing new reserves.  Any reductions in our capital expenditures to stay within internally generated cash flow (which could be adversely affected by declining commodity prices) and cash on hand will make replacing produced reserves more difficult.  If our cash flow from operations and cash on hand are not sufficient to fund our capital expenditure budget, we may be limited in our ability to access additional debt, equity or other methods of financing on an economic or timely basis to replace our proved reserves.

Lower oil and natural gas prices could negatively impact our ability to borrow.

As of December 31, 2014, borrowing availability under our revolving bank credit facility was $750 million, less outstanding borrowings of $447 million and letters of credit of less than $1 million, resulting in net availability of $302 million.  Availability is determined semi-annually by our lenders and is based on oil, NGLs and natural gas prices and on our proved reserves.  Substantially all of our oil and natural gas properties are pledged as collateral under the Fifth Amended and Restated Credit Agreement (the “Credit Agreement”) governing our revolving bank credit facility.  The Credit Agreement limits our ability to incur additional indebtedness based on specified financial covenants, ratios or other criteria.  Sustained and/or lower oil, NGLs and natural gas pricesThese limitations in the future could result in a reduction in credit availabilitycapital markets and alsoour recently constrained capital budget may adversely affect our ability to satisfy these covenants, ratios orsustain our production at 2016 levels.  We cannot be certain that financing for future capital expenditures will be available if needed, and to the extent required, on acceptable terms. For additional financing risks, see “–Risks Relating to Our Industry, Our Business and Our Financial Condition.”

Additional deepwater drilling laws, regulations and other criteria and thus could reduce our ability to incur additional indebtedness and our ability to replace reserves.

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The Company could face additional requirements if it does not comply with the terms of its probation.

On January 3, 2013, the Company (i) pled guilty to one felony count under the Clean Water Act for altering monthly produced water discharge samples for the Ewing Banks 910 platform in 2009 and one misdemeanor count under the Clean Water Act for failure to report the discharge of a small amount of oil from the same platform in November 2009, (ii) paid a $0.7 million fine and $0.3 million for community service and (iii) entered into an environmental compliance program subject to a third-party audit. Under the agreement, the Company was placed on a three-year term of probation, which ends on January 3, 2016. The probation terms require that the Company commit no further environmental law violations, comply with an Environmental Compliance Plan during the probation period and take no adverse action against personnel who cooperatedrestrictions, delays in the investigation. The agreement further stipulates that the Government will not seek any further criminal charges against the Company in this matter. Failure to comply with the termsprocessing and approval of the agreement could lead to additional requirements and/or operating restrictions.

More stringent regulatory initiatives relating to offshore explorationdrilling permits and production activities may have an adverse effect on our results of operations, financial position and liquidity.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals, and substantial rules adopted, by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. The federal government, acting through the U.S. Department of the Interior and its implementing agencies that have since evolved into the present day BOEM and BSEE, has issued various rules, NTLs and temporary drilling moratoria.  These rules and requirements impose or result in added environmental and safety measures upon exploration, development, oil spill-response and production operatorsdecommissioning plans, and other related developments in the Gulf of Mexico includingmay have a material adverse effect on our business, financial condition, or results of operations.

In recent years, we have expanded our drilling efforts on deepwater projects in the following:

TheseGulf of Mexico.  The BSEE and the BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters.  Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill-response, and decommissioning plans and possible additional regulatory initiatives may serve to effectively slow down the pace ofcould result in difficult and more costly actions and adversely affect or delay new drilling and production operationsongoing development efforts.  Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico dueand, as a result, are continuing to adjustmentsdevelop and implement new, more restrictive requirements.  For example, in operating proceduresApril 2016, the BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and certification practices as well as increased lead timesmaintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements.  Also, in April 2016, the BOEM published a proposed rule that would update existing air emissions requirements relating to obtain explorationoffshore oil and production plan reviews, develop drilling applications, and apply for and receive new well permits.  These new requirements also increase the cost of preparing permit applications and increase the cost of each new well, particularly for wells drilled in the deepwaternatural gas activity on the OCS.  WeThe BOEM regulates these air emissions in connection with its review of exploration and development plans, and ROWs and RUEs applications.  The proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. These rules and other potential subsequent rulemakings could become subjectfurther restrict offshore air emissions.  

Among other adverse impacts, these additional measures could delay operations, disrupt our operations or increase the risk of leases expiring before exploration and development efforts have been completed due to fines,the time required to develop new technology.  This would result in increased financial assurance requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties or orders requiring us to modifyshut-in production at one or suspendmore of our operations in the Gulf of Mexico if we fail to comply with these requirements.  Moreover, if similar oilfacilities.  If material spill incidents were to occur in the future, in the Gulf of MexicoUnited States or elsewhereother countries where we conduct operations, the relevant governmental authoritiessuch an event may occur could elect to again issue directives to temporarily cease drilling activities.  Inactivities and, in any event, they may from time to time issue further safety and environmental regulatory initiativeslaws and regulations regarding offshore oil and natural gas exploration and development, activities,any of which any one or more of such events could have a material adverse effect on our production activities as well asbusiness.  We cannot predict with any certainty the full impact of any new laws or regulations on our financial position, results ofdrilling operations and liquidity.

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Requirements imposed by the BOEM and BSEE related to the decommissioning, plugging, and abandonment of offshore facilities could significantly impactor on the cost or availability of operating our business.

In additioninsurance to the NTLs discussed previously, the BOEM issued NTL No. 2010-G05 dated effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” – wells, platforms and pipelines that are no longer producingcover some or serving exploration or support functions related to an operator’s lease – in the Gulf of Mexico. This NTL sets forth more stringent standards for decommissioning timing requirements by requiring that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities which are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts which could cause an increase, perhaps materially, in our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future ARO required to meet such increased costs. We have continued to review and revise our ARO estimates each year following BOEM’s issuance of this NTL. The increase in decommissioning activity in the Gulf of Mexico expected over the next few years as a result of the NTL may result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related ARO.

To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied.  In addition, in August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements for companies operating in federal waters.  If BOEM were to increase its financial assurance requirements substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. The significant reductions in oil and natural gas pricing since the middle of 2014 may also adversely impact the BOEM’s financial assurance determinations with respect to the Company. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated.  Any such suspension or termination could materially adversely affect our financial condition and results of operations. In addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and abandonment liabilities if financial strength and reliability criteria are not met.  

Proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs.

The EPA has adopted new regulations under the CAA that, among other things, require additional emissions controls for the production of oil, NGLs and natural gas, including New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequentlyrisks associated with such production activities. The final regulations require, among other things, the reduction of VOC emissions through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could significantly increase our costs of development and production.operations.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We are and could be exposed to uninsured losses in the future.  As of December 31, 2016, we carry named windstorm coverage of $150 million for a total loss only (“TLO”) on our Ship Shoal 349 (Mahogany) platform and do not have named wind storm coverage on any other of our properties.  We currently carry insurance coverage for certain events besides the named windstorm coverage for Mahogany in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which includes named windstorm TLO coverage for Mahogany).  Along with having exposure for named wind storms at all of our properties, and limited coverage at our Mahogany property, we have additional exposure due to retention amounts within the Energy Package and limitations of the policies.

The occurrence of a significant accident or other event not covered in whole or in part by our insurance could have a material adverse impact on our financial condition and operations.  Our insurance does not protect us against all operational risks.  We do not carry business interruption insurance.  In May and June 2014,2016, we renewedentered into our insurance policies covering well control, hurricane damage, general liability and pollution.  These policies reduce, but do notin no way totally mitigate our risk as we are exposed to amounts for retention and co-insurance, limits on coverage and some events that are not insured.  These policies expire in May and June 2015.2017.  Renewal of these policies at a cost commensurate with current premiums is not assured.  We also have other smaller per-occurrence retention amounts for various other events.  In addition, pollution and environmental risks are generally not fully insurable, as gradual seepage and pollution are not covered under our policies.  Because third-party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees.

OPA requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill.  We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS.  If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement.  We cannot predict at this time whether OPA will be amended, or whether the level of financial responsibility required for companies operating on the OCS will be increased.  In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

  For some risks, we mayhave not obtainobtained insurance ifas we believe the cost of available insurance is excessive relative to the risks presented.  We may take on further risks in the future if we believe the cost is excessive to the risks.  The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claims and Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on insurance coverage.

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Insurance for well control and hurricane damage may become significantly more expensive for less coverage and some losses currently covered by insurance may not be covered in the future.

Due to insurance claims in recent years associated withIn the past, hurricanes in the Gulf of Mexico and globalhave caused catastrophic losses and property damage and welldamage.  Well control insurance coverage has become more limited and the cost of such coverage has become both more costly and more volatile.volatile over the past five years.  The insurance market may further change dramatically in the future due to thehurricane damage, major oil spill that occurred in 2010 at BP’s Macondo well inspills or other events.  

  In the deepwater Gulf of Mexico. As of December 31, 2014, virtually all offuture, our PV-10 value of proved reserves attributable to our Gulf of Mexico properties is on platforms that are covered under our current insurance policies for named windstorm damage. Our insurers may not continue to offer us the type and level of our currentwhat we view as reasonable coverage, or our costs may increase substantially as a result of increased premiums and therepremiums.  There could be an increased risk of uninsured losses that may have been previously insured.  We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurance companies will not pay our claims.  The occurrence of any or all of these possibilities could have a material adverse effect on our financial condition and results of operations.

Commodity derivative positions may limit our potential gains.

In order to manage our exposure to price risk in the marketing of our oil and natural gas, we may periodically enter into oil and natural gas price commodity derivative positions with respect to a portion of our expected production.  As of December 31, 2016, we did not have any open commodity derivative positions.  During the first quarter of 2017, we entered into commodity derivative contracts and may enter into more contracts in the future.  While these commodity derivative positions are intended to reduce the effects of volatile crude oil and natural gas prices, they may also limit future income if crude oil and natural gas prices were to rise substantially over the price established by such positions.  In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

See Financial Statements and Supplementary Data– Note 68 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on derivative transactions.

Competition for oil and natural gas properties and prospects is intense; some of our competitors have larger financial, technical and personnel resources that may give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil, NGLs and natural gas and securing trained personnel.  Many of our competitors have financial resources that allow them to obtain substantially greater technical expertise and personnel than we have.  We actively compete with other companies in our industry when acquiring new leases or oil and natural gas properties.  For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder.  Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit.  Our competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay.pay or finance.  On the acquisition opportunities made available to us, we compete with other companies in our industry for such properties through a private bidding process, direct negotiations or some combination thereof.  Our abilitycompetitors may have significantly more capital resources and less expensive sources of capital.  In addition, they may be able to acquire additionalgenerate acceptable rates of return from marginal prospects anddue to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.their lower costs of capital.  If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.  The availability of properties for acquisition depends largely on the divesting practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors we cannot control or influence.  Additional requirements and limitations recently imposed on us and our ability to finance such acquisitions may put us at a competitive disadvantage for acquiring properties.  These risks are described above in the risk factor entitled: Requirements imposedWe may be unable to provide the financial assurances demanded by the BOEM to cover our decommissioning obligations in the amounts and BSEE relatedunder the time periods required by the BOEM.  If extensions and modifications to the decommissioning, plugging,BOEM’s current or future demands are needed and abandonment ofcannot be obtained, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore facilities could significantly impact the cost of operating our business.leases.  

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We conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which presents unique operating risks.

The deep shelf and the deepwater of the Gulf of Mexico are areas that have had less drilling activity due, in part, to their geological complexity, depth and higher cost to drill and ultimately develop.  There are additional risks associated with deep shelf and deepwater drilling that could result in substantial cost overruns and/or result in uneconomic projects or wells.  Deeper targets are more difficult to interpret with traditional seismic processing.  Moreover, drilling costs and the risk of mechanical failure are significantly higher because of the additional depth and adverse conditions, such as high temperature and pressure.  For example, the drilling of deepwater wells requires specific types of rigs with significantly higher day rates, and limited availability, as compared to the rigs used in shallower water.  Deepwater wells have greater mechanical risks because the wellhead equipment is installed on the sea floor.  Deepwater development costs can be significantly higher than development costs for wells drilled on the conventional shelf because deepwater drilling requires larger installation equipment, sophisticated sea floor production handling equipment, expensive state-of-the-art platforms and investment in infrastructure.infrastructure investments.  Deep shelf development can also be more expensive than conventional shelf projects because deep shelf development requires more drilling days and higher drilling and service costs due to extreme pressure and temperatures associated with greater depths.  Accordingly, we cannot assure you that our oil and natural gas exploration activities in the deep shelf, the deepwater and elsewhere will be commercially successful.

Our estimates of future asset retirement obligationsARO may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico.

We are required to record a liability for the present value of our ARO to plug and abandon inactive non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations.  These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths.  Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or such requirements may be interpreted more restrictive interpretation,restrictively, and asset removal technologies are constantly evolving, which may result in additional or increased costs.  As a result, we may make significant increases or decreases to our estimated ARO in future periods.  For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes.  The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact.  Accordingly, our estimate of future ARO couldwill differ dramatically from whatour recorded estimate if we may ultimately incur ashave a result of platform damage.damaged platform.

As described above inDuring 2016, the risk factor titled “Newadditional requirements imposed by the BOEM and BSEE related to the decommissioning, plugging, and abandonment of offshore facilities could significantly impact the cost of operating our business,”under the BOEM’s NTL 2010-G05 increased our liability for ARO by accelerating#2016-N01, once fully implemented, will increase the time frame for plugging, abandonment and removal for somecosts of our platformsoperations and reduce the availability of surety bonds due to the increased demands for such bonds in a low-price commodity environment.  In December 2016, the BOEM further increasedissued an order on our sole liability after issuing regulation interpretationsproperties for additional financial assurances.  In January 2017, in a notice to stakeholders, the BOEM issued the January 2017 Extension, which affected scope and requirements.extended the implementation timeline for providing financial assurance under NTL #2016-N01 by an additional six months for non-sole liability properties with certain exceptions.  In addition,February 2017, the potential increaseBOEM withdrew the orders it issued in decommissioning activityDecember 2016 affecting sole liability properties to allow time for the new Administration to review the complex financial assurance program.  This withdrawal rescinded the Order to Provide Additional Security issued to us in December 2016.  However, the Gulf of Mexico overBOEM may re-issue sole liability orders before the next several years as a resultend of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  The BOEM’s NTL could likely result#2016-N01 has given broader interpretation authority to BOEM’s district personnel, which increases the difficulty in compliance with the new NTL.  In addition, increased demand for salvage contractors and equipment resultingcould result in increased estimates ofcosts for plugging and abandonment operations.  These items have, and removalmay further increase our costs and increasesmay impact our liquidity adversely.

We may be obligated to pay costs related to other companies that have filed for bankruptcy or have indicated they are unable to pay their share of costs in joint ownership arrangements.  

In our contractual arrangements of joint ownership of oil and gas interests with other companies, we are obligated to pay our share of operating, capital and decommission costs, and have the right to a share of revenues after royalties and certain other cash inflows.  If one of the companies in the arrangement is unable to pay its agreed upon share of costs, generally the other companies in the arrangement are obligated to pay the non-paying company’s obligations.  Under joint operating agreements (“JOAs”) among working interest owners, the non-paying company would typically lose the right to future revenues, which would be applied to the non-paying company’s share of operating, capital and decommissioning costs.  If future revenues are insufficient to defray these additional costs, especially in cases where the well has stopped producing and is being decommissioned, we could be obligated to pay certain costs of the defaulting party.  In addition, the liability to the U.S. Government for obligations of lessees under federal oil and gas leases, including obligations for decommissioning costs, is generally joint and several among the various co-owners of the lease, which means that any single owner may be liable to the U.S. Government for the full amount of all lessees’ obligations under the lease.  In certain circumstances, we also could be liable for decommissioning liabilities on federal oil and gas leases that we previously owned and the assignee is bankrupt or unable to pay its decommissioning costs.  For example, we have in the past received a demand for payment of such costs related ARO.to property interests that were sold several years prior.  These indirect obligations would affect our costs, operating profits and cash flows negatively and could be substantial.

We may not be in a position to control the timing of development efforts, associated costs or the rate of production of the reserves from our non-operated properties.

As we carry out our drilling program, we may not serve as operator of all planned wells.  We have limited ability to exercise influence over the operations of some non-operated properties and their associated costs.  Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities.  The success and timing of exploration and development activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

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Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development activities may be unsuccessful for many reasons, including adverse weather conditions, cost overruns, equipment shortages, geological issues, technical difficulties and mechanical difficulties.  Moreover, the successful drilling of a natural gas or oil well does not assure us that we will realize a profit on our investment.  A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical.  In addition to their costs, unsuccessful wells hinder our efforts to replace reserves.

Our oil and natural gas exploration and production activities, including well stimulation and completion activities, which include, among other things, hydraulic fracturing, involve a variety of operating risks, including:

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.  We could also incur substantial losses as a result of:

Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from tropical storms, hurricanes or other adverse weather conditions.  These conditions can cause substantial damage to facilities and interrupt production.  Companies that incur environmental liabilities frequently also confront third-party claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.  Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.  We may have liability for releases of hazardous substances at our properties by prior owners, operators, other third parties, or at properties we have sold.  As a result, we could incur substantial liabilities that could reduce or eliminate funds available for exploration, development and acquisitions or result in the loss of property and equipment.

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The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenues or curtailment of production from factors specifically affecting the Gulf of Mexico.

The geographic concentration of our properties along the U.S. Gulf Coast and adjacent waters on and beyond the OCS means that some or all of our properties could be affected by the same event should the Gulf of Mexico experience:

Because a majority of our properties could experience the same conditions at the same time, these conditions could have a greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.  For example, net production of approximately 8.7 Bcfe was deferred as a result of damage caused primarily by Hurricane Ike in 2009 and Hurricane Isaac caused net production deferral of approximately 2.9 Bcfe in 2012.

As  In 2016, 2015 and 2014, we increase our onshore operations, we will be subjectexperienced production deferrals of lower amounts due to different risk factors that could impact loss of revenues or curtailment of production for these geographies.

Onshore oilother events, such as pipeline shut-ins and gas exploration and production operations share similar risk factors to offshore, but also have some different regulations, interpretation of regulations and enforcement by the particular state in which the operations are conducted. Until 2011, our experience has primarily been with offshore operations. We are subject to and must comply with the various state regulations and work effectively with the state agencies, and failure to do so may impact our operations.platform maintenance.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations. We utilize hydraulic fracturing techniques in connection with developing our properties in the Spraberry field and other onshore properties. The process involves the injection of water, sand or other proppants and chemicals under pressure into the rock formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. The EPA, however, recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA Underground Injection Control Program and issued permitting guidance covering such activities in February 2015. In addition, the EPA has commenced a broad study of the potential environmental effects of hydraulic fracturing activities, and the agency has indicated that it expects to issue its study report in 2015. A number of other federal agencies, including the U.S. Department of Energy, Department of Interior, and White House Council on Environmental Quality, are also studying various aspects of hydraulic fracturing. The results of these studies could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. From time to time, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local governments have adopted, and other states and local governments are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations, including states in which we operate. For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

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Properties that we acquire may not produce as projected and we may be unable to immediately identify liabilities associated with these properties or obtain protection from sellers against them.of such properties.

Our business strategy includes growing by making acquisitions, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests.  Our acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:

Our assessment of the acquired properties will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies.  In the course of our due diligence, we have historically not physically inspected every well, platform or pipeline.  Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion, well bore issues or groundwater contamination.  We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks.  We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.

Increasing our reserve base through acquisitions is an important part of our business strategy.  We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.  In particular, we may face significant challenges in consolidating functions and integrating procedures, personnel and operations in an effective manner.  The failure to successfully integrate such properties or businesses into our business may adversely affect our business and results of operations.  Any acquisition we make may involve numerous risks, including:

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties.  To the extent that we acquire properties substantially different from the properties in our primary operating region or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as with acquisitions within our primary operating region.  We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make.

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Estimates of our proved reserves depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in the estimates or underlying assumptions will materially affect the quantities of and present value of future net revenues from our proved reserves.

The process of estimating oil and natural gas reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors.  Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of our reserves at December 31, 2014.2016.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Oil and natural gas reserve quantities, under Part II, Item 7 for a discussion of the estimates and assumptions about our estimated oil and natural gas reserves information reported in Business under Part I, Item 1, Properties under Part I, Item 2 and Financial Statements and Supplementary Data – Note 21 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K.

In order to prepare our year-end reserve estimates, our independent petroleum consultant projected our production rates and timing of development expenditures.  Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary and may not be under our control.  The process also requires economic assumptions about matters such as crude oil and natural gas prices, operating expenses, capital expenditures, taxes and availability of funds.  Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved oil and natural gas reserves is the current market value of our estimated oil and natural gas reserves.  In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate, which prices are not reflective of the substantially lower prices realized in December 2014 and January 2015.estimate.  Actual future prices and costs may differ materially from those used in the present value estimate.

Prospects that we decide to drill may not yield oil or natural gas in commercial quantities or quantities sufficient to meet our targeted rate of return.

A prospect is an area in which we own an interest, could acquire an interest or have operating rights, and have what our geoscientists believe, based on available seismic and geological information, to be indications of economic accumulations of oil or natural gas.  Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial seismic data processing and interpretation.  There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable.  The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities.  We cannot assure that the analysis we perform using data from other wells, more fully explored prospects and/or producing fields will accurately predict the characteristics and potential reserves associated with our drilling prospects.  The recent downturn inSustained low crude oil, NGLs and natural gas pricing will also significantly impact the projected rates of return of our projects without the assurance of significant reductions in costs of drilling and development.  To the extent we drill additional wells in the deepwater and/or on the deep shelf, our drilling activities could become more expensive.  In addition, the geological complexity of deepwater and deep shelf and various onshore formations may make it more difficult for us to sustain our historical rates of drilling success.  As a result, we can offer no assurance that we will find commercial quantities of oil and natural gas and, therefore, we can offer no assurance that we will achieve positive rates of return on our investments.

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Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production.  The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities.  Our ability to market our production depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities, which in most cases are owned and operated by third parties.  Our failure to obtain such services on acceptable terms could materially harm our business.  We may be required to shut in wells because of a reduction in demand for our production or because of inadequacy or unavailability of pipelines or gathering system capacity.  If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.  We have, in the past, been required to shut in wells when hurricanes have caused or threatened damage to pipelines and gathering stations.  For example, in September 2008, as a result of Hurricane Ike, two of our operated platforms and eight non-operated platforms were toppled and a number of platforms, third-party pipelines and processing facilities upon which we depend to deliver our production to the marketplace were damaged.  In 2012, under threat of Hurricane Isaac, we shut in most of our offshore production for a period of 10 to 25 days.  Similar shut-ins of lower magnitude occurred in 2013.

In some cases, our wells are tied back to platforms owned by partiesthird-parties who do not have an economic interest in our wells and we cannot be assured that such parties will continue to process our oil and natural gas.

Currently, a portion of our oil and natural gas is processed for sale on platforms owned by partiesthird-parties with no economic interest in our wells and no other processing facilities would be available to process such oil and natural gas without significant investment by us.  In addition, third-party platforms could be damaged or destroyed by hurricanes which could reduce or eliminate our ability to market our production.  As of December 31, 2014, 122016, 10 fields, accounting for approximately 12.86.9 Bcfe (or 12%8%) of our 20142016 production, are tied back to separate, third-party owned platforms.  There can be no assurance that the owners of such platforms will continue to process our oil and natural gas production.  If any of these platform operators ceases to operate their processing equipment, we may be required to shut in the associated wells, construct additional facilities or assume additional liability to re-establish production.

If third-party pipelines connected to our facilities become partially or fully unavailable to transport our crude oil and natural gas or oil, or if the prices charged by these third-party pipelines increase, our revenues or costs could be adversely affected.

We depend upon third-party pipelines that provide delivery options from our facilities.  Because we do not own or operate these pipelines, their continued operation is not within our control.  If any of these third-party pipelines become partially or fully unavailable to transport crude oil and natural gas, and oil, or if the gas quality specification for the natural gas pipelines changes so as to restrict our ability to transport natural gas on those pipelines, our revenues could be adversely affected.  For example, in 2013, various pipelines were shut down causing production deferral of approximately 6.3 Bcfe.  Our Mississippi Canyon 506 field (Wrigley) was the field most significantly affected by the shutdowns in recent years, as it was shut down for all of 2013 and more than half of 2014.

Certain third-party pipelines have submitted or have made plans to submit requests to increase the fees they charge us to use these pipelines.  These increased fees could adversely impact our revenues or operating costs, either of which would adversely impact our operating profits, cash flows and reserves.

We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration, development, production and transportation of crude oil and natural gas and operational safety.  Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with such legal requirements may harm our business, results of operations and financial condition.  We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:

Volume measurements:

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Our Fields

On December 31, 2014,2016, we had two fields of major individual significance (which we define as having year-end proved reserves of 15% or more of the Company’s total proved reserves, calculated on an energy equivalent basis). The Spraberry field (Yellow Rose) is located in the Permian Basin in West Texas and: the Ship Shoal 349 field (Mahogany) is located on the conventional shelf in the Gulf of Mexico. Below is a descriptionMexico and the Fairway Field, located in the Mobile Bay area of Alabama, which includes the associated Yellowhammer gas processing plant located onshore in Alabama.  Following are descriptions of these fields.

Spraberry Field (Yellow Rose).

The Spraberry field is located in the Permian Basin in West Texas. We acquired a 100% working interest in approximately 21,900 net acres in connection with the acquisition of properties (the ‘Opal Properties”) from Opal Resources LLC and Opal Resources Operating LLC (collectively, “Opal”) in May 2011.  In separate transactions, we acquired approximately 9,500 net acres in 2011 and approximately 2,200 net acres in 2013. We are the operator for these properties.  The Spraberry field was discovered in 1935 and extends over several counties in West Texas comprising about 1.6 million acres. The field is 150 miles long and 75 miles wide, and it has undergone much change and expansion over the years, both aerially and vertically. The correlative interval is now over 3,500 feet thick and includes the Clearfork, Upper Spraberry, Lower Spraberry, Dean, and Wolfcamp formations. These formations are correlative over the area but are lenticular in nature and vary in thickness, porosity, and permeability even over short distances. The general completion technique includes hydraulic fracturing and installation of sucker rod pumps. During 2014, we drilled 38 wells, which included nine horizontal wells.  During 2013, we drilled 32 wells, which included five horizontal wells.  During 2012, we drilled 64 wells, which included one horizontal well. Cumulative field production through 2014 is approximately 6.4 MMBoe (38.3 Bcfe) from our wells. In 2015, we plan to drill one horizontal well. Total proved reserves associated with our interest in the Spraberry field were 37.3 MMBoe (223.6 Bcfe) at December 31, 2014, 38.2 MMBoe (229.3 Bcfe) at December 31, 2013 and 31.6 MMBoe (189.8 Bcfe) at December 31, 2012.

The following presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Spraberry field over the past three years.

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Ship Shoal 349 Field (Mahogany).

Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, in 375 feet of water.Louisiana.  The field area covers Ship Shoal blocks 349 and 359, with a single production platform on Ship Shoal block 349.349 in 375 feet of water.  Phillips Petroleum Company discovered the field in 1993.  We initially acquired a 25% working interest in the field from BP Amoco in 1999.  In 2003, we acquired an additional 34% working interest through a transaction with ConocoPhillips that increased our working interest to approximately 59%, and we became the operator of the field in December 2004.  In early 2008, we acquired the remaining working interest from Apache Corporation (“Apache”) and we now own a 100% working interest in this field.  Cumulative field production through 20142016 is approximately 37.343.5 MMBoe gross (223.6 Bcfe gross).gross.  This field is a sub-salt development with eight productive horizons below salt at depths up to 17,00019,000 feet.  In 2010, we developed a reservoir simulation model to determine the most optimal future development plan (the “2010 Development Plan”).  As a result, in 2011, we drilled and completed one development well and one exploration well.  In 2012, two additional wells were sidetracked, one well was drilled and completed, and another well was drilled to target depth.  In 2013, the well reaching target depth in 2012 was completed, one well was drilled and completed and we had one well being drilled.  In 2014, the well being drilled in 2013 was completed and we drilled and completed another well.  A third well was spud at year end 2014, and,drilling was suspending in January 2015, drilling on this well was suspended at an intermediate casing point pending higher crude oil prices.resumed during 2016 and completion occurred in the first quarter of 2017.  All of the wells drilled under the 2010 Development Plan have been successful.  Total proved reserves associated with our interest in this field were 18.819.8 MMBoe (112.9 Bcfe) at December 31, 2014, 22.92016, 22.3 MMBoe (137.7 Bcfe) at December 31, 20132015, and 22.718.8 MMBoe (136.3 Bcfe) at December 31, 2012.2014.

The following presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Ship Shoal 349 field over the past three years.

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The following is a description of the remainder of our top 10 properties, measured by proved reserves at December 31, 2014, three of which are located on the conventional shelf and five are located in the deepwater. We do not believe that individually any of these properties are of major significance (each has proved reserves which comprise less than 15% of our year-end total proved reserves, calculated on a natural gas equivalent basis).

Fairway Field.

The Fairway fieldField is comprised of Mobile Bay Area blocks 113 (Alabama State Lease #0531) and 132 (Alabama State Lease #0532) and located in 25 feet of water, approximately 35 miles south of Mobile, Alabama.  We acquired our initial 64.3% working interest, along with operatorship, in the Fairway field,Field and associated Yellowhammer gas processing plant, from Shell Offshore, Inc. (“Shell”) in August 2011 and acquired the remaining working interest of 35.7% in September 2014.  The field was discovered in 1985 with Well 113 #1 (now called JA).  Development drilling began in 1990 and was completed in 1991 with the addition of four wells, each drilled from separate surface locations.  The five producing wells came on line in late 1991.  As of December 31, 2014,2016, six wells have been drilled, one of which was a replacement well.  Cumulative field production through 20142016 is approximately 125.4129.9 MMBoe gross (752.3 Bcfe gross).gross.  This field is a Norphlet sand dune trend development with one producing horizon at an approximate depth of 21,300 feet.  During December 2014, production fromTotal proved reserves associated with our interest in this field net towere 13.7 MMBoe at December 31, 2016, 14.0 MMBoe at December 31, 2015, and 14.6 MMBoe at December 31, 2014.

The following is a description of the remainder of our interest, averaged 47 Bblstop 10 properties, measured by proved reserves at December 31, 2016, two of which are located on the conventional shelf and six of which are located in the deepwater.  We do not believe that individually any of these properties are of major significance (each has proved reserves which comprise less than 15% of our year-end total proved reserves, calculated on a barrel of oil per day, 1,696 Bbls of NGLs per day and 25.9 MMcf of natural gas per day, for total production of 6,065 Boe per day (36.4 MMcfe per day)equivalent basis).

Viosca Knoll 783 Field (Viosca Knoll 783 Lease (Tahoe) and Viosca Knoll 784 Lease (SE Tahoe)).  The Viosca Knoll 783 field is located off the coast of Louisiana, approximately 140 miles southeast of New Orleans, Louisiana in 1,500 to 1,700 feet of water.  The field area covers Viosca Knoll blocks 783 and 784, with subsea tiebacks to two platforms in Main Pass 252.  Shell discovered the Tahoe prospect in 1984 and the SE Tahoe prospect in 1996.  We acquired a 70% working interest in the Tahoe lease and a 100% working interest in the SE Tahoe lease from Shell in 2010.  We are the operator forof these properties.  Cumulative field production through 20142016 is approximately 96.3100.1 MMBoe gross (577.6 Bcfe gross).gross.  The Tahoe prospect is a supra-salt (above the salt layer) development with two productive horizons at depths ranging to 10,300 feet.  The SE Tahoe prospect is also a supra-salt development with one productive horizon at a depth of 9,325 feet.  As of December 31, 2014,2016, 16 wells have been drilled at the Tahoe prospect, eight of which have been successful and one successful well has been drilled at the SE Tahoe prospect.  During December 2014,2016, production from this field, net to our interest, averaged 212 Bbls125 barrels of crude oil per day, 1,362 Bbls977 barrels of NGLs per day and 18.8 MMcf12,989 Mcf of natural gas per day, for total production of 4,7003,267 Boe per day (28.2 MMcfe per day).

Mississippi Canyon 243 Field (Matterhorn).  Mississippi Canyon 243 field is located off the coast of Louisiana, approximately 100 miles southeast of New Orleans, in 2,552 feet of water.  The field area covers Mississippi Canyon block 243, with a single floating, tension leg production platform on Mississippi Canyon block 243.  Société Nationale Elf Aquitaine discovered the field in 2002.  We acquired a 100% working interest in the field from Total E&P USA Inc. (“Total E&P”) in 2010.  Cumulative field production through 2014 is approximately 31.7 MMBoe gross (190.4 Bcfe gross).  This field is a supra-salt development with 17 productive horizons at depths ranging to 9,850 feet.  As of December 31, 2014, 30 wells have been drilled, 13 of which have been successful.  During 2013, we drilled one well, which began production in 2013, and we drilled another well, that had reached target depth but had not yet been completed. During 2014, the well that had reached target depth in 2013 was completed.  During December 2014, production from this field, net to our interest, averaged 1,553 Bbls of oil per day, 463 Bbls of NGLs per day and 12.2 MMcf of natural gas per day, for total production of 4,051 Boe per day (24.3 MMcfe per day).

Main Pass 108 Field.  Main Pass 108 field consists of Main Pass blocks 107, 108 and 109.  This field is located off the coast of Louisiana approximately 50 miles east of Venice in 50 feet of water.  We acquired our working interests in these blocks, which range from 33% to 100%, in a transaction with Kerr-McGee Oil and Gas Corporation and we are the operator for the majority of these properties.  The field produces from a number of low relief, predominantly stratigraphically trapped sands.  The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Big Hum.  As of December 31, 2014, 48 wells have been drilled in this field, 30 of which were successful.  Cumulative field production through 2014 is approximately 53.1 MMBoe gross (318.7 Bcfe gross).  One new well reached target depth in 2011 and began production in 2012.  In addition, one workover was performed in 2012.  In 2013, we drilled and completed one well, which began production during 2013.  During December 2014, production from this field, net to our interest, averaged 118 Bbls of oil per day, 178 Bbls of NGLs per day and 10.7 MMcf of natural gas per day, for total production of 2,086 Boe per day (12.5 MMcfe per day).day.

Mississippi Canyon 782 Field (Dantzler).   Mississippi Canyon 782 field is located off the coast of Louisiana, approximately 160 miles southeast of New Orleans, Louisiana in 6,600 feet of water.  The field area covers Mississippi Canyon block 782 and 738.  We have a 20% working interest, which is operated by Noble Energy.  We, along with Noble Energy, discovered the field in 2013.  This field is currently under developmentdeveloped as a subsea tieback to the Thunderhawk Field approximately 12 miles to the northwest.  The field is a three-way closure trapped against a salt wall.  There arewith two pay horizons, the upper Miocene U5 and U6 sands.age pay horizons.  Cumulative field production through 2016 is approximately 3.4 MMBoe gross.  As of December 31, 2014,2016, two wells have been drilled, both of which have been successful, with one well beginning production in the fourth quarter of 2015 and the other well beginning production in the first quarter of 2016.  During December 2016, production from this field, net to our interest, averaged 1,863 barrels of crude oil per day, 91 barrels of NGLs per day and 1,432 Mcf of natural gas per day, for total production of 2,193 Boe per day.  

Mississippi Canyon 698 Field (Big Bend).  Mississippi Canyon 698 is approximately 160 miles southeast of New Orleans, Louisiana in 7,221 feet of water.  The field area covers portions of Mississippi Canyon blocks 697, 698, and 742.  We have a 20% working interest, which is operated by Noble Energy.  We, along with Noble Energy, discovered the field in 2012.  This field is a subsea tieback to the Thunderhawk Field approximately 18 miles to the northwest.  Cumulative field production through 2016 is approximately 6.9 MMBoe gross.  The field is a supra-salt development with two productive horizons at depths ranging from 14,660’ to 15,533’ total vertical depth.  As of December 31, 2016, one well has been drilled and successful, with the well beginning production in the fourth quarter of 2015.  During December 2016, production from this field, net to our interest, averaged 2,187 barrels of crude oil per day, 53 barrels of NGLs per day and 983 Mcf of natural gas per day, for total production of 2,404 Boe per day.

Main Pass 108 Field.  Main Pass 108 field consists of Main Pass blocks 107, 108 and 109.  This field is located off the coast of Louisiana approximately 50 miles east of Venice, Louisiana in 50 feet of water.  We acquired our working interests in these blocks, which range from 33% to 100%, in a transaction with Kerr-McGee Oil and Gas Corporation (“Kerr-McGee”) and we are the operator of this field.  The field produces from a number of low relief, predominantly stratigraphically trapped sands.  The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Big Hum.  As of December 31, 2016, 48 wells have been drilled in this field, 30 of which were successful.  Cumulative field production through 2016 is approximately 47.3 MMBoe gross.  One new well reached target depth in 2011 and began production in 2012.  In addition, one workover was performed in 2012.  In 2013, we drilled and completed one well, which began production during 2013.  During December 2016, production from this field, net to our interest, averaged 211 barrels of crude oil per day, 317 barrels of NGLs per day and 17,190 Mcf of natural gas per day, for total production of 3,393 Boe per day.

Mississippi Canyon 243 Field (Matterhorn).  Mississippi Canyon 243 field is located off the coast of Louisiana, approximately 100 miles southeast of New Orleans, Louisiana in 2,552 feet of water.  The field area covers Mississippi Canyon block 243, with a single floating, tension leg production platform.  Société Nationale Elf Aquitaine discovered the field in 2002.  We acquired a 100% working interest in the field from Total E&P USA Inc. (“Total E&P”) in 2010.  Cumulative field production through 2016 is approximately 35.9 MMBoe gross.  This field is a supra-salt development with 17 productive horizons, with the maximum depth of 9,850 feet.  As of December 31, 2016, 30 wells have been drilled, 13 of which have been successful.  During 2013, we drilled one well, which began production in 2013.  We also began drilling another well in 2013, which was completed during 2014.  During December 2016, production from this field, net to our interest, averaged 1,261 barrels of crude oil per day, 193 barrels of NGLs per day and 3,151 Mcf of natural gas per day, for total production of 1,979 Boe per day.

Ewing Bank 910.  Ewing Bank 910 is located approximately 68 miles off the Louisiana coast in 560 feet of water.  The field area covers Ewing Bank blocks 910 and 954, and South Timbalier block 320 and 311.  Kerr-McGee discovered the field in 1996.  We own a 100% working interest in the main field pays, having acquired a 40% working interest from Kerr-McGee in 2006 and the remaining 60% from Petrobras America Inc. in 2014.  Three recently successful deep wells are subject to a 50% working interest with Walter Oil and Gas Corporation.  A single production platform is located on Block 910.  Cumulative field production through 2016 is approximately 16.0 MMBoe gross.  Production occurs from Pliocene and upper Miocene channel/levee sands set up by a combination of stratigraphic and structural traps.  A newly acquired wide angle azimuth seismic data set is expected to help confirm several recently identified drilling opportunities in the field area.  Since its discovery, 11 wells have been drilled, of which bothnine were successful.  During December 2016, production from this field, net to our interest, averaged 994 barrels of crude oil per day, 209 barrels of NGLs per day and 3,722 Mcf of natural gas per day, for total production of 1,824 Boe per day.

Brazos A-133 Field.  Brazos A-133 field is located 85 miles east of Corpus Christi, Texas in 200 feet of water.  The field was discovered in 1978 by Cities Service Oil Company with production commencing in the same year.  There are five active platforms, three of which are production platforms.  Cumulative field production through 2016 is approximately 154.1 MMBoe gross from the Middle Miocene Tex W and Big Hum sections.  The bulk of the production is from the Big Hum CM-7 sand, which is a 4-way closure downthrown to the Corsair Fault and bisected by antithetic faults.  The top of the CM-7 sand is at a subsea depth of 12,000 feet.  Since its discovery, 22 wells have been successfuldrilled, of which 17 were successful.  We own a 50% working interest, of which 25% was obtained through a transaction with Kerr-McGee in 2006 and are targetedan additional 25% was obtained through a transaction with Chevron U.S.A. Inc. in 2015.  During December 2016, production from this field, net to our interest, averaged 3 barrels of crude oil per day and 6,291 Mcf of natural gas per day, for firsttotal production in the first quarter of 2016.1,052 Boe per day.

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Viosca Knoll 823 Field (Virgo).  Viosca Knoll 823 field is located off the coast of Louisiana, approximately 125 miles southeast of New Orleans, Louisiana in 1,014 feet of water.  The field area covers Viosca Knoll block 823 and Viosca Knoll block 822, with a single fixed leg production platform on Viosca Knoll block 823.  Total E&P discovered the field in 1997.  We acquired a 64% working interest in the field from Total E&P in 2010 and we are the operator forof this property.  Cumulative field production through 20142016 is approximately 21.722.8 MMBoe gross (130.4 Bcfe gross).gross.  This field is a supra-salt development with 17 productive horizons at depths ranging to 13,335 feet.  As of December 31, 2014,2016, 14 wells have been drilled, 10 of which have been successful.  During December 2014,2016, production from this field, net to our interest, averaged 128 Bbls381 barrels of crude oil per day, 145 Bbls88 barrels of NGLs per day and 5.2 MMcf8,341 Mcf of natural gas per day, for total production of 1,1371,859 Boe per day (6.8 MMcfe per day).day.

East Cameron 321. East Cameron 321 field is located approximately 97 miles off the Louisiana coastline in 225 feet of water.  Two production facilities, the “A” and “B” platforms, are located on the block.  This field has multiple sands that are productive in faulted, structural traps.  These sands are Pleistocene Ang B in age.  As of December 31, 2014, 76 wells have been drilled of which 58 have been successful.  In 2014 we drilled and completed one well.  Cumulative field production through 2014 is approximately 94.6 MMBoe gross (567.3 Bcfe) gross.  We own a 100% working interest in the field and are the operator of the field.  This field is producing at a restricted rate as a result of a damaged departing gas sales line.  During January to October 2014, which was prior to the departing gas sales line damage, production from this field, net to our interest, averaged 890 Bbls of oil per day and 0.2 MMcf of natural gas per day, for total production of 928 Boe per day (5.6 MMcfe per day).

Main Pass 283. Main Pass 283 field consists of Main Pass blocks 284, 279 and 283 and Viosca Knoll Block 734.  This field is located off the coast of Louisiana approximately 75 miles east of Venice in 315 feet of water.  We acquired our working interests in these blocks in 2003, which range from 50% to 100%, in a transaction with ConocoPhillips.  The field produces from a number of low relief, predominantly stratigraphically trapped sands.  The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Cristellaria I.  Cumulative field production through 2014 is approximately 24.3 MMBoe gross (145.8 Bcfe gross).  As of December 31, 2014, 12 wells have been drilled in this field, of which 10 were successful.  During December 2014, production from this field, net to our interest, averaged 398 Bbls of oil per day, 195 Bbls of NGLs per day and 3.9 MMcf of natural gas per day, for total production of 1,251 Boe per day (7.5 MMcfe per day).

Proved Reserves

Our proved reserves were estimated by NSAI, our independent petroleum consultant, and amounts provided in this Annual Report on Form 10-K are consistent with filings we make with other federal agencies.  Our proved reserves as of December 31, 20142016 are summarized below and the mix by product was 52%44% oil, 13%11% NGLs and 35%45% natural gas determined using the energy-equivalent ratio noted below.  

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The reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves is as follows (in millions):

Changes in Proved Reserves

Our total proved reserves increased more than production, resulting in a net increase, andat December 31, 2016 were 120.074.0 MMBoe compared to 76.4 MMBoe at December 31, 2014 compared to 117.7 MMBoe at December 31, 2013.  The change between periods is a result2015, representing an overall decrease of extensions and discoveries of 9.7 MMBoe, acquisitions of 6.1 MMBoe and positive net revisions of 4.1 MMBoe, partially offset by 17.62.4 MMBoe.  After accounting for 15.4 MMBoe of production.  Increases for extensions and discoveries2016 production, total revisions were primarily at Mississippi Canyon 782 (Dantzler) related to two wells and the Spraberry field related to 51 wells.  Increases from acquisitionsa positive 13.0 MMBoe.  Positive technical revisions were primarily14.2 MMBoe, while negative revisions due to acquiring interests in the Woodside Properties and increasing ownership in the Fairway field.  Revisionslower commodity prices were impacted by various fields, with the primary changes being increases at the Fairway and Mississippi Canyon 800 fields, partially offset by decreases at the Spraberry and Ship Shoal 349 (Mahogany) fields.  estimated to be 1.2 MMBoe.  

See Development of Proved Undeveloped ReserReservesves below for a table reconciling the change in proved undeveloped reserves during 2014.2016.  See Financial Statements and Supplementary Data– Note 21 – Supplemental Oil and Gas Disclosuresunder Part II, Item 8 in this Form 10-K for additional information.

Our estimates of proved reserves, PV-10 and standardized measure as of December 31, 20142016 are calculated based upon SEC mandated 20142016 unweighted average first-day-of-the-month crude oil and natural gas benchmark prices, which are substantially above prices realized in December 2014may or may not represent current prices.  Using the SEC methodology and January 2015.  The pricesprior to certain adjustments for quality, transportation, fees, energy content and regional price differentials, the price of crude oil NGLs anddeclined to $39.25 per barrel for 2016 year-end compared to $46.79 per barrel for 2015 year-end.  For natural gas, have declined substantially since June 2014.  The spotthe price of WTI crude oil has decreased from $107.00 per barrel in the middle of June 2014 to as low as $44.00 per barrel in January 2015.  In recent months, Henry Hub spot prices for natural gas have declined to lower than $3.00$2.48 per McfMMBtu for 2016 year-end compared to average$2.59 per MMBtu for 2015 year-end.  If prices during 2014 well in excess of $4.00 per Mcf. Sustained lower prices will result infall below the prices used in our estimates through year-end 2015 being substantially lower,2016 levels, which, absent significant proved reserve additions, willmay reduce future estimated proved reserve volumes due to lower economic limits and economic return thresholds for undeveloped reserves, as well as impact our results of operations, cash flows, quarterly full cost impairment ceiling tests and volume-dependent depletion cost calculations.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 in this Form 10-K for additional information.  

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Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our estimated proved reserve information as of December 31, 20142016 included in this Form 10-K was prepared by our independent petroleum consultants, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  The scope and results of their procedures are summarized in a letter included as an exhibit to this Form 10-K.  The primary technical person at NSAI responsible for overseeing the preparation of the reserves estimates presented herein has B.S. and M.S. degrees in Civil Engineeringbeen practicing consulting petroleum engineering at NSAI since 2013 and has been a Registered Professional Engineer in the State of Texas for 26 years and a member of the Society of Petroleum Engineers for over 30 years. He has over 37 years total experience in the oil and gas industry, with over 2314 years of reservoir engineeringprior industry experience. His areas of experience are the continental shelf and deepwater Gulf of Mexico, San Juan Basin, onshore and offshore Mexico, offshore Africa, and unconventional gas sources worldwide.  NSAI has informed us that he meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.

We maintain an internal staff of reservoir engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates.  Additionally, our senior management reviews any significant changes to our proved reserves on a quarterly basis.  Our Director of Reservoir Engineering Director has served in that capacity since 2013, as Reservoir Engineering Manager since 2006,over 27 years of oil and as Staff Reservoir Engineer upon joininggas industry experience and has managed the preparation of public company reserve estimates the last 13 years.  He joined the Company in 2004. Prior to joiningmid-2016 after spending the Company, hepreceding 12 years as Director of Corporate Engineering for Freeport-McMoRan Oil & Gas.  He has also served as a Reservoir Engineer at Shell, then VP of Reservoir Engineering at Freeport-McMoRanin various engineering and strategic planning roles with both Kerr-McGee Oil & Gas and later as Manager Acquisitions Engineering at Matrix Oil & Gas.with Conoco, Inc.  He receivedearned a Bachelor of Science degree in Petroleum Engineering Science from Iowa StateTexas A&M University in 1972.1989 and a Master’s degree in Business Administration from the University of Houston in 1999.

Reserve Technologies

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate.  To achieve reasonable certainty, our independent petroleum consultant employed technologies that have been demonstrated to yield results with consistency and repeatability.  The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests.  The accuracy of the estimates of our reserves is a function of: