wti-10k_20161231.htm

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑

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 ☑

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 ☑ 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 ☑ 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. ☑

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 ☑

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $81,638,000 based on the closing sale price of $2.32 per share as reported by the New York Stock Exchange on June 30, 2016.

The number of shares of the registrant’s common stock outstanding on February 28, 2017 was 137,674,372.

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.

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.

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 in the Gulf of 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-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 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 increased our exploration and development activities in the deepwater, which has led to a greater percentage of our total production coming from deepwater wells.

As of December 31, 2016, we have interests in offshore leases covering approximately 750,000 gross acres (450,000 net acres) spanning across the Outer Continental Shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama. On a gross acreage basis, the conventional shelf constitutes approximately 490,000 gross acres and deepwater constitutes approximately 260,000 gross acres of our offshore acreage.

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultants, our total proved reserves at December 31, 2016 were 74.0 million barrels of oil equivalent (“MMBoe”) or 444.0 billion cubic feet of gas equivalent (“Bcfe”). Approximately 64% of our proved reserves as of such date were classified as proved developed producing, 23% as proved developed non-producing and 13% as proved undeveloped. Classified by product, our proved reserves at December 31, 2016 were 44% crude oil, 11% natural gas liquids (“NGLs”) and 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 $755 million before consideration of cash outflows related to asset retirement obligations (“ARO”). Our PV-10 after considering future cash outflows related to ARO was $478 million, and our standardized measure of discounted future cash flows was also $478 million as of December 31, 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 Reserves 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. With 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. Although the current economic environment has caused us to take a conservative approach towards acquisitions, our acquisition team continues to identify and evaluate properties that will fit our profile and that we believe will add strategic and financial value to our 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 in 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%.

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 consist 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.

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 return. While we will continue to evaluate opportunistic acquisitions, we expect that our acquisition activities may be reduced until the outlook for the future commodity pricing environment improves or unless financing is available on reasonable terms that would not significantly impair our available liquidity.

Additional information on 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 7 – 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 2012, some of our exploration projects were higher risk deepwater projects with potentially higher returns than our previous risk/reward profile. 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. 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 invested capital if it occurs. When projects are extremely capital intensive and involve substantial risk, we often seek participants to share the risk. We completed one, five and six offshore wells (gross) in 2016, 2015 and 2014, 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.

Due 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 at $125 million. Although this is an increase from the $49 million of 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, respectively. We have flexibility in our 2017 capital expenditure budget because we have no long term rig commitments and no current pressure from co-owners to drill or complete a well. Some of our expenditures planned for 2017 are expected to 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 plans include spending $78 million in 2017 for ARO, compared to $72 million spent on ARO in 2016. We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans. See Risk Factors under Part I, Item 1A in this Form 10-K for additional information.

Our business strategy is to acquire, explore and develop oil and natural gas reserves on the OCS, the area of our historical success and technical expertise, which we believe will 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 commenced in the second half of 2014 created more uncertainty about future exploration and development. Although commodity prices stabilized at higher levels during the second half of 2016 compared to the first half of 2016, prices are still low from historical levels and price volatility occurring in the last three years continues to affect our evaluation of potential returns and risks of our drilling projects. We 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. Also, we expect opportunities will arise as producers seek to divest their properties for short-term cash flow needs. Our plans for the short-term include operating within cash flow, maintaining liquidity, meeting our financial obligations, and 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 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. 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 other cash needs of the business. We plan to continue to evaluate acquisition opportunities and financing options.

The oil and natural gas industry is highly competitive. We currently operate in the Gulf of Mexico 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 companies and individual producers and operators. Many of these competitors are large, well established companies that have financial and other resources substantially greater than 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 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.

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 2016, approximately 43% of our sales were to Shell Trading (US) Co. and 20% were to Vitol Inc., with no other customer comprising greater than 10% of our 2016 revenues. Due to the free trading nature of the oil and natural gas markets in the Gulf of Mexico, 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.

General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulations 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, 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. Sales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices.

The 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. We 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.

These departments and agencies have substantial enforcement 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. The 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 allows non-pipeline natural gas sellers, including producers, to effectively compete 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 is subject to state regulations, which may change from time to time.

The OCSLA, which is administered by the 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 assurance of open access service on pipelines located on the OCS, and to provide non-discriminatory rates and conditions of service on such pipelines. The BOEM issued a final rule, effective August 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 such sales and purchases to the 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 pursued by the FERC, Congress and the states will continue.

While these federal and state regulations for the most part affect us only indirectly, they are intended to 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 and regulations. As it relates to intrastate crude oil, condensate and NGL 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 NGL pipelines will affect us in a way that materially differs from the way they affect other crude oil, condensate and NGL 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.

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.

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 costly to comply with, and a failure to comply may result in substantial administrative, civil and even criminal penalties 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 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 is significant. These costs are considered a normal, recurring cost of our on-going operations. Our competitors are subject to the same laws and regulations.

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.

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,” and the disposal of such oil and natural gas exploration, development and production wastes is usually regulated by state law. 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.” A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could potentially subject such wastes to more stringent handling, disposal and cleanup requirements. Other 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 the oil and natural gas industry in 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. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Moreover, the U.S. Congress and the EPA, in addition to some state and regional efforts, have in recent years considered legislation or regulations to reduce emissions of greenhouse gases. These efforts have included consideration of cap-and-trade programs, carbon taxes, and greenhouse gas monitoring and reporting programs. In the absence of federal greenhouse gas limitations, the EPA has determined that greenhouse gas emissions present a danger to public health and the environment, and it has adopted regulations that, among other things, restrict emissions of greenhouse gases under existing provisions of the CAA and may require the installation of control 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 together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of greenhouse gas emissions from specified offshore production sources. See Risk Factors under Part I, Item 1A of this Form 10-K for further discussion.

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, the BOEM has raised OPA’s damages liability cap to $134 million. 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, 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. 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.

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. The treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from our onshore 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.

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. 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).

Certain flora and fauna that have been officially classified as “threatened” or “endangered” are protected by the Endangered Species Act (“ESA”). This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. We conduct operations on leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or 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.

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.

We operate our business as a single segment. See Selected Financial Data under Part II, Item 6 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for our financial information.

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.

As of December 31, 2016, we employed 302 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.

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, other reports and amendments 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.

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.

Further declines in crude oil, NGLs and natural gas prices or 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. 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. The significantly reduced prices for our crude oil, NGLs and natural gas production in 2016 and 2015 have substantially decreased our revenues on a per unit basis and have also reduced 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:

The prices of crude oil, domestic natural gas and NGLs have declined substantially starting in the second half of 2014. The average price per barrel of West Texas Intermediate (“WTI”) crude oil was over $90.00 in 2014, approximately $49.00 in 2015 and approximately $43.00 per barrel in 2016. This decrease in prices has impacted all companies throughout the oil and gas industry. Natural gas and NGL prices have also been negatively affected by excess natural gas production, high levels of stored natural gas and weather conditions affecting demand. During 2014, the average Henry Hub spot price for natural gas was above $4.00 per MMBtu compared to approximately $2.60 per MMBtu during 2015 and approximately $2.50 per MMBtu in 2016. Development activities in shale and other resource plays 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 domestic oil drilling activities. Although oil prices have increased somewhat from the lows of the first quarter of 2016, margins are still low compared to historical levels. An environment of continued low crude oil, NGLs and natural gas prices would materially and adversely affect our future business, financial condition, results of operations, liquidity, ability to finance planned capital 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.

Availability 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.

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, we may 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 review the carrying value of our oil and natural gas properties quarterly for possible impairment. Impairment of proved properties under our full cost oil and gas accounting method is largely driven by the present value of future net revenues of proved reserves estimated using SEC mandated 12-month unweighted first-day-of-the-month commodity prices. In 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 declined in 2015, 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 first three quarters of 2016 which totaled $279 million. If prices fall below levels received during 2016, this would impact our estimated future revenues. In addition, lower crude oil, NGLs and natural gas prices may reduce our estimates of the reserve volumes that may be economically recovered, which would reduce the total value of our proved reserves.

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. Also, no assurance can be given that commodity price decreases will not affect our reserve 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 reasonably certain to be drilled within five years of the date of booking. This rule may limit our potential to book additional PUDs as we pursue our drilling program. If current prices decline, we also may be compelled to postpone the drilling of PUDs until prices recover. If we postpone drilling of PUDs 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.

Our PUDs comprised 13% of our total proved reserves as of December 31, 2016 and require additional future expenditures and/or activities to convert these into producing reserves. As circumstances change, we cannot provide assurance that all future expenditures will be made and that activities will be entirely successful in converting these reserves. 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 a portion of our PUDs, which could have put us in a position of not being able to control the timing of development activities. Furthermore, there can be no assurance that all of our PUDs 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. All 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 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 and we believe our access to capital markets remains limited at this time. Compared to prior years, we significantly reduced our capital expenditures in 2016 and continue to have a low capital expenditure budget for 2017 in order to conserve capital and target projects with the highest probability of acceptable 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. These limitations in the capital markets and our recently constrained capital budget may adversely affect our ability to sustain 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 restrictions, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and other related developments in the Gulf of Mexico may 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 Gulf 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 could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are continuing to develop and implement new, more restrictive requirements. For example, in April 2016, the BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and maintenance 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 offshore oil and natural gas activity on the OCS. The 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 further 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 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 shut-in production at one or more of our facilities. If material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such 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 2016, we entered into our insurance policies covering well control, hurricane damage, general liability and pollution. These policies reduce, but in no way totally mitigate our risk as we are exposed to amounts for retention and co-insurance, limits on coverage and events that are not insured. These policies expire in May and June 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 have not obtained insurance as 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.

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.

In the past, hurricanes in the Gulf of Mexico have caused catastrophic losses and property damage. Well control insurance coverage has become more limited and the cost of such coverage has become both more costly and more volatile over the past five years. The insurance market may further change dramatically in the future due to hurricane damage, major oil spills or other events.

In the future, our insurers may not continue to offer what we view as reasonable coverage, or our costs may increase substantially as a result of increased premiums. 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.

In order to manage our exposure to price risk in the marketing of our oil and natural gas, we 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 8 – 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 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 competitors may have significantly more capital resources and less expensive sources of capital. In addition, they may be able to generate acceptable rates of return from marginal prospects due to 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: 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.

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, 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 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 ARO 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 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 will differ dramatically from our recorded estimate if we have a damaged platform.

During 2016, the additional requirements under the BOEM’s NTL #2016-N01, once fully implemented, will increase the costs of our operations 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 issued an order on our sole liability properties for additional financial assurances. In January 2017, in a notice to stakeholders, the BOEM issued the January 2017 Extension, which 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 February 2017, the BOEM withdrew the orders it issued in December 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 BOEM may 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 liabilities. The BOEM’s NTL #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 could result in increased costs for plugging and abandonment operations. These items have, and may further increase our costs and may 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 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:

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, 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.

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. In 2016, 2015 and 2014, we experienced production deferrals of lower amounts due to other events, such as pipeline shut-ins and platform maintenance.

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 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.

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, 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. 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. Sustained 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 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.

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 third-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 third-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, 2016, 10 fields, accounting for approximately 6.9 Bcfe (or 8%) of our 2016 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 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, 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:

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and natural gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See Business – Regulation under Part I, Item 1 in this Form 10-K for a more detailed explanation of regulations impacting our business.

Our operations may incur substantial liabilities to comply with environmental laws, endangered species laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and regardless of whether our operations met previous standards in the industry at the time they were conducted. Our permits require that we report any incidents that cause or could cause environmental damages. Examples of recent proposed and final regulations include the following:

These and other regulatory changes could significantly increase our capital expenditures and operating costs or could result in delays to or limitations on our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows. See Business – Regulation under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental and endangered species regulations.

The ONNR’s revised interpretations on determining appropriate allowances related to transportation and processing costs for natural gas could cause us to pay substantial amounts in back royalties and in future royalties.

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 initiate requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant for which we had gas processed. In the second quarter of 2015, pursuant to the initiative, the Company received requests from the ONRR for additional data regarding the Company’s transportation and processing allowances on natural gas production that was processed through a specific processing plant. The Company also received a preliminary determination notice from the ONRR asserting its preliminary determination that the Company’s allocation of certain processing costs and plant fuel use at another processing plant were impermissibly allowed as deductions in the determination of royalties owed under Federal oil and gas leases. The Company has submitted responses covering certain plants and certain time periods and has not yet received responses as to the preliminary determination asserting the reasonableness of its revised allocation methodology of such costs. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for current and prior periods. The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.

Should we fail to comply with all applicable FERC and CFTC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the EP Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Under the Commodity Exchange Act and regulations promulgated thereunder by the CFTC, the CFTC has adopted anti-market manipulation rules relating to the prices or futures of commodities. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, or the CFTC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability. See Business – Regulation under Part I, Item 1 in this Form 10-K for further description of our regulations.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

The EPA has determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. At the federal level, no comprehensive climate change legislation has been implemented. The EPA, however, has adopted regulations under the federal Clean Air Act to restrict emissions of greenhouse gases. For example, the EPA imposes preconstruction and operating permit requirements on certain large stationary sources that are already potential sources of certain other significant pollutant emissions. The EPA also adopted rules requiring the monitoring and reporting of greenhouse gas emissions on an annual basis from specified large greenhouse gas emission sources in the United States, including onshore and offshore oil and natural gas production facilities. Federal agencies have also begun directly regulating emissions of methane, a greenhouse gas, from oil and natural gas operations. For example, in June 2016, the EPA published new source performance standards for methane and volatile organic compound emissions from certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector. Compliance with these rules could result in increased compliance costs on our operations.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and a number of states and grouping of 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 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. Our offshore operations are particularly at risk from severe climatic events. If any such climate effects were to occur, they could have an adverse effect on our business, financial condition and results of operations. See – Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses. – under this Item 1A.

The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business.

In July 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “DF Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The DF Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the DF Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In one of its rulemaking proceedings still pending under the DF Act, the CFTC issued on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us in connection with covered derivatives activities to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although the Company expects to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that the Company uses for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margins. Posting of collateral could impact liquidity and reduce cash available to the Company for its needs. The DF Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The full impact of the DF Act and related regulatory requirements upon the Company’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The DF Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, increase our exposure to less creditworthy counterparties or reduce liquidity. If we reduce our use of derivatives as a result of the DF Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the DF Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the DF Act is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

We own a non-producing platform in a highly regulated National Marine Sanctuary, which increases our compliance costs and subjects us to risk of significant fines and penalties if we do not maintain compliance.

We own a non-producing platform located in a National Marine Sanctuary in the Gulf of Mexico that is subject to special federal laws and regulations. We have been working with BSEE for over four years to obtain a permit to plug, abandon and remediate the well and production platform, but BSEE has refused to provide a decommissioning permit. Unique regulations related to operations in the National Marine Sanctuary include, among other things, prohibition of drilling activities within certain protected areas, restrictions on substances that may be discharged, 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, including cessation of production from wells associated with this platform.

Our operations could be adversely impacted by security breaches, including cyber-security breaches, which could affect our production of oil and natural gas or could affect other parts of our business.

We rely on our information technology infrastructure and management information systems to operate and record aspects of our business. Although we take measures to protect against cybersecurity risks, including unauthorized access to our confidential and proprietary information, our security measures may not be able to detect or prevent every attempted breach. Similar to other companies, we have experienced cyber-attacks, although we have not suffered any material losses related to such attacks. Security breaches include, among other things, illegal hacking, computer viruses, or acts of vandalism or terrorism. A breach could result in an interruption in our operations, unauthorized publication of our confidential business or proprietary information, unauthorized release of customer or employee data, violation of privacy or other laws and exposure to litigation. Any of these security breaches could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

To a large extent, we depend on the services of our senior management. The loss of the services of any of our senior management, including Tracy W. Krohn, our Founder, Chairman and Chief Executive Officer; Jamie L. Vazquez, our President; John D. Gibbons, our Senior Vice President and Chief Financial Officer; Thomas P. Murphy, our Senior Vice President and Chief Operations Officer; and Stephen L. Schroeder, our Senior Vice President and Chief Technical Officer, could have a negative impact on our operations. We do not maintain or plan to obtain for the benefit of the Company any insurance against the loss of any of these individuals. See Executive Officers of the Registrant under Part I following Item 3 in this Form 10-K for more information regarding our senior management team.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

In past years, legislation was proposed that would have made significant changes to U.S. tax laws, including certain U.S. federal income tax provisions currently available to oil and gas companies. Such legislative proposals have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available to us, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Counterparty credit risk may negatively impact the conversion of our accounts receivables to cash.

Substantially all of our accounts receivable result from crude oil, NGLs and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic or other conditions. In recent years, market conditions resulting in downgrades to credit ratings of energy merchants affected the liquidity of several of our purchasers.

Our producing fields are located in federal and state waters in the Gulf of Mexico in water depths ranging from less than 10 feet up to 7,300 feet. The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, with high initial production rates. The following map provides the locations of our 10 largest fields as of December 31, 2016, based on quantities of proved reserves on an energy equivalent basis. At December 31, 2016, these fields accounted for approximately 83% of our proved reserves.

The following table provides information for our 10 largest fields determined using quantities of proved net reserves on an energy equivalent basis as of December 31, 2016. Deepwater refers to acreage in over 500 feet of water. Our interests in several of our offshore fields are owned by our wholly-owned subsidiary, W & T Energy VI, LLC. Unless indicated otherwise, “drilling” or “drilled” in the field descriptions below refers to when the drilling reached target depth, as this measurement usually has a higher correlation to changes in proved reserves compared to using the SEC’s definition for completion.

		Percent Oil and NGLs of			2016 Average Daily Equivalent Sales Rate (Boe/d) ⁽¹⁾
Field Name	Field Category	Proved Reserves ⁽¹⁾			Gross		Net
Ship Shoal 349 (Mahogany)	Shelf		84	%		5,909		4,924
Fairway	Shelf		23	%		6,237		4,678
Viosca Knoll 783 (Tahoe/SE Tahoe)	Deepwater		27	%		4,974		3,383
Miss. Canyon 782 (Dantzler)	Deepwater		75	%		19,888		3,232
Miss. Canyon 698 (Big Bend)	Deepwater		93	%		18,251		2,966
Main Pass 108	Shelf		18	%		3,728		2,906
Miss. Canyon 243 (Matterhorn)	Deepwater		81	%		2,260		2,260
Ewing Bank 910	Deepwater		67	%		3,233		1,408
Brazos A133	Shelf		—			2,587		1,078
Viosca Knoll 823 (Virgo)	Deepwater		30	%		1,605		994

On December 31, 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 Ship Shoal 349 field (Mahogany) located on the conventional shelf in the Gulf of Mexico 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.

Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, Louisiana. The field area covers Ship Shoal blocks 349 and 359, with a single production platform on Ship Shoal block 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 2016 is approximately 43.5 MMBoe gross. This field is a sub-salt development with eight productive horizons below salt at depths up to 19,000 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, drilling was suspending in January 2015, drilling 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 19.8 MMBoe at December 31, 2016, 22.3 MMBoe at December 31, 2015, and 18.8 MMBoe at December 31, 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.

	Year Ended December 31,
	2016		2015		2014
Net Sales:
Oil (MBbls)		1,332		2,313		2,020
NGLs (MBbls)		159		97		104
Natural gas (MMcf)		1,871		3,764		3,433
Total oil equivalent (MBoe)		1,802		3,037		2,697
Total natural gas equivalents (MMcfe)		10,812		18,221		16,181
Average daily equivalent sales (Boe/day)		4,924		8,320		7,388
Average daily equivalent sales (Mcfe/day)		29,543		49,922		44,330
Average realized sales prices:
Oil ($/Bbl)	$	31.97	$	42.73	$	87.21
NGLs ($/Bbl)		17.88		21.27		46.46
Natural gas ($/Mcf)		2.38		2.86		4.40
Oil equivalent ($/Boe)		27.67		36.77		72.73
Natural gas equivalent ($/Mcfe)		4.61		6.13		12.12
Average production costs: ⁽¹⁾
Oil equivalent ($/Boe)	$	5.16	$	3.30	$	4.12
Natural gas equivalent ($/Mcfe)		0.86		0.55		0.69

The Fairway Field 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 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, 2016, six wells have been drilled, one of which was a replacement well. Cumulative field production through 2016 is approximately 129.9 MMBoe gross. This field is a Norphlet sand dune trend development with one producing horizon at an approximate depth of 21,300 feet. Total proved reserves associated with our interest in this field were 13.7 MMBoe at December 31, 2016, 14.0 MMBoe at December 31, 2015, and 14.6 MMBoe at December 31, 2014.

	Year Ended December 31,
	2016		2015		2014
Net Sales:
Oil (MBbls)		9		10		7
NGLs (MBbls)		400		319		415
Natural gas (MMcf)		7,817		8,277		6,899
Total oil equivalent (MBoe)		1,712		1,708		1,571
Total natural gas equivalents (MMcfe)		10,272		10,250		9,428
Average daily equivalent sales (Boe/day)		4,678		4,680		4,305
Average daily equivalent sales (Mcfe/day)		28,065		28,083		25,830
Average realized sales prices:
Oil ($/Bbl)	$	41.15	$	47.22	$	101.94
NGLs ($/Bbl)		16.72		18.97		27.41
Natural gas ($/Mcf)		2.42		2.60		4.07
Oil equivalent ($/Boe)		17.32		16.40		25.53
Natural gas equivalent ($/Mcfe)		2.89		2.73		4.26
Average production costs: ⁽¹⁾
Oil equivalent ($/Boe)	$	7.95	$	8.96	$	10.73
Natural gas equivalent ($/Mcfe)		1.32		1.49		1.79

The following is a description of the remainder of our top 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 equivalent basis).

Viosca Knoll 783 Field (Viosca Knoll 783 (Tahoe) and Viosca Knoll 784 (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 of these properties. Cumulative field production through 2016 is approximately 100.1 MMBoe 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, 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 2016, production from this field, net to our interest, averaged 125 barrels of crude oil per day, 977 barrels of NGLs per day and 12,989 Mcf of natural gas per day, for total production of 3,267 Boe per 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 developed as a subsea tieback to the Thunderhawk Field approximately 12 miles to the northwest. The field is a three-way closure trapped salt with two upper Miocene age pay horizons. Cumulative field production through 2016 is approximately 3.4 MMBoe gross. As of December 31, 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 nine 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 drilled, 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 an 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 total production of 1,052 Boe per day.

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 of this property. Cumulative field production through 2016 is approximately 22.8 MMBoe gross. This field is a supra-salt development with 17 productive horizons at depths ranging to 13,335 feet. As of December 31, 2016, 14 wells have been drilled, 10 of which have been successful. During December 2016, production from this field, net to our interest, averaged 381 barrels of crude oil per day, 88 barrels of NGLs per day and 8,341 Mcf of natural gas per day, for total production of 1,859 Boe per day.

Our proved reserves were estimated by NSAI, our independent petroleum consultant, and amounts provided in this Form 10-K are consistent with filings we make with other federal agencies. Our proved reserves as of December 31, 2016 are summarized below and the mix by product was 44% oil, 11% NGLs and 45% natural gas determined using the energy-equivalent ratio noted below.

							Total Energy-Equivalent Reserves ⁽²⁾
Classification of Proved Reserves ⁽¹⁾	Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Oil Equivalent (MMBoe)		Natural Gas Equivalent (Bcfe)		% of Total Proved			PV-10 ⁽³⁾ (In millions)
Proved developed producing		16.6		6.1		147.5		47.3		283.9		64	%	$	449
Proved developed non-producing		10.0		1.5		35.6		17.4		104.3		23	%		229
Total proved developed		26.6		7.6		183.1		64.7		388.2		87	%		678
Proved undeveloped		6.3		0.6		14.7		9.3		55.8		13	%		77
Total proved		32.9		8.2		197.8		74.0		444.0		100	%	$	755

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):

Our total proved reserves at December 31, 2016 were 74.0 MMBoe compared to 76.4 MMBoe at December 31, 2015, representing an overall decrease of 2.4 MMBoe. After accounting for 15.4 MMBoe of 2016 production, total revisions were a positive 13.0 MMBoe. Positive technical revisions were 14.2 MMBoe, while negative revisions due to lower commodity prices were estimated to be 1.2 MMBoe.

See Development of Proved Undeveloped Reserves below for a table reconciling the change in proved undeveloped reserves during 2016. See Financial Statements and Supplementary Data– Note 21 – Supplemental Oil and Gas Disclosures under 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, 2016 are calculated based upon SEC mandated 2016 unweighted average first-day-of-the-month crude oil and natural gas benchmark prices, which may or may not represent current prices. Using the SEC methodology and prior to certain adjustments for quality, transportation, fees, energy content and regional price differentials, the price of crude oil declined to $39.25 per barrel for 2016 year-end compared to $46.79 per barrel for 2015 year-end. For natural gas, the price declined to $2.48 per MMBtu for 2016 year-end compared to $2.59 per MMBtu for 2015 year-end. If prices fall below the 2016 levels, which, absent significant proved reserve additions, may 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.

Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our estimated proved reserve information as of December 31, 2016 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 been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience. 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 has over 27 years of oil and gas industry experience and has managed the preparation of public company reserve estimates the last 13 years. He joined the Company in mid-2016 after spending the preceding 12 years as Director of Corporate Engineering for Freeport-McMoRan Oil & Gas. He has also served in various engineering and strategic planning roles with both Kerr-McGee Oil & Gas and with Conoco, Inc. He earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1989 and a Master’s degree in Business Administration from the University of Houston in 1999.

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:

We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. We report all natural gas production information net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs. We convert barrels to Mcfe using an energy-equivalent ratio of six Mcf to one barrel of 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 substantially.

Our proved undeveloped reserves (“PUDs”) were estimated by NSAI, our independent petroleum consultant. Future development costs associated with our PUDs at December 31, 2016 were estimated at $98.9 million.

	Year Ended December 31,
	2016			2015			2014
Proved undeveloped reserves, beginning of year		7.4			36.7			31.6
Reductions:
Ship Shoal 349 (Mahogany)		(1.9	)		—			—
Mississippi Canyon 698 (Big Bend)		(0.9	)		(1.0	)		—
Viosca Knoll 823 (Virgo)		—			(2.0	)		—
Mississippi Canyon 538/582 (Medusa)		—			(0.3	)		—
Mississippi Canyon 782 (Dantzler)		—			(4.1	)		—
Spraberry (Yellow Rose - sold in 2015)		—			(24.9	)		(4.7	)
Subtotal — reductions		(2.8	)		(32.3	)		(4.7	)
Balance after reductions		4.6			4.4			26.9
Additions:
Ship Shoal 349 (Mahogany)		2.4			1.9			0.8
Viosca Knoll 823 (Virgo)		2.1			—			0.6
Spraberry (Yellow Rose)		—			—			3.9
Mississippi Canyon 782 (Dantzler)		—			—			4.1
Mississippi Canyon 243 (Matterhorn)		0.2			0.6			—
Ewing Bank 910		—			0.5			—
Other changes		—			—			0.4
Subtotal — additions		4.7			3.0			9.8
Proved undeveloped reserves, end of year		9.3			7.4			36.7

See Business under Part I, Item 1, Our Fields in Item 2 above and Financial Statements and Supplementary Data – Note 7 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information.

We believe that we will be able to develop all but 1.3 MMBoe, or approximately 14%, of the total 9.3 MMBoe classified as PUDs at December 31, 2016, within five years from the date such reserves were initially recorded. The lone exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. One of the sidetrack PUD locations in this field was originally recorded in our proved reserves as of December 31, 2010. The development of this PUD will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop this PUD location in 2023.

Our capital budget for 2017 is $125 million, which excludes potential acquisitions, with over 50% allocated for development. Three of our four PUDs as of December 31, 2016 are scheduled to be drilled in 2017.

The following summarizes our leasehold at December 31, 2016. Deepwater refers to acreage in over 500 feet of water.

Approximately 74% of our net acreage is held by production. We have the right to propose future exploration and development projects on the majority of our acreage.

Regarding the undeveloped leasehold, 47,500 net acres (40%) of the total 118,647 net undeveloped acres could expire in 2017, 19,975 net acres (17%) could expire in 2018, 32,720 net acres (27%) could expire in 2019, 11,912 net acres (10%) could expire in 2020, and 6,720 net acres (6%) could expire in 2020 and beyond. In making decisions regarding drilling and operations activity for 2017 and beyond, we give consideration to undeveloped leasehold that may expire in the near term in order that we might retain the opportunity to extend such acreage.

Our net acreage decreased 90,160 net acres (17%) from December 31, 2015 due to lease expirations and relinquishments.

For the years 2016, 2015 and 2014, our net daily production averaged 41,980 Boe, 46,709 Boe, and 48,317 Boe, respectively. Production decreased in 2016 from 2015 primarily due to natural production declines and divestiture of the Yellow Rose properties, partially offset by production from Mississippi Canyon 698 field (Big Bend) and the Mississippi Canyon 782 field (Dantzler), which began production in the fourth quarter of 2015, and from one well completed during the year. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations under Part II, Item 7 in this Form 10-K for additional information.

The following presents historical information about our produced oil, NGLs and natural gas volumes from all of our producing fields over the past three years.

Refer to the descriptions of our 10 largest fields reported earlier in this Item 2, Properties, for historical information about our produced volumes from our Ship Shoal 349/359 field (Mahogany) and the Fairway Field over the past three fiscal years, which have proved reserves exceeding 15% of our total proved reserves. Also refer to Selected Financial Data – Historical Reserve and Operating Information under Part II, Item 6 in this Form 10-K for additional historical operating data, including average realized sale prices and production costs.

The following presents our ownership interest at December 31, 2016 in our productive oil and natural gas wells. A net well represents our fractional working interest of a gross well in which we own less than all of the working interest.

As presented in the tables below, our drilling activity decreased in 2016 compared to 2015 and 2014. As the Yellow Rose properties were divested during 2015 and we do not currently have any onshore drilling activities, historical data for onshore drilling was excluded from the table below.

The table below is based on the SEC’s criteria of completion or abandonment to determine productive wells drilled.

The following table summarizes our development and exploration offshore wells completed over the past three years.

Our success rates related to our development and exploration wells drilled was 100% in each of the last three years.

During January 2017, we completed the A-18 offshore development well at the Ship Shoal 349 field (Mahogany). This well was spud in 2014, but drilling was suspended in 2015 and resumed in 2016.

The level of our investment in oil and gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas; acquisition opportunities; liquidity and financing options; and the results of our exploration and development activities. Due to the sustained lower commodity price environment and the outlook for the remainder of 2017, we have set our 2017 capital expenditure budget at $125 million, which excludes potential acquisitions. Although this is an increase from the $49 million capital expenditures incurred in 2016, our current plan for 2017 is a significant reduction from 2015 and 2014 investment levels of $231 million and $630 million, respectively. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Expenditures under Part II, Item 7 in this Form 10-K for additional capital expenditures information.

Financial Assurance Requirements by the BOEM. In the first quarter of 2016, we received several orders from the BOEM demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs. We filed various appeals to the IBLA concerning these orders. The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM orders through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to May 31, 2017.

In July 2016, the BOEM issued NTL #2016-N01, related to obligations for decommissioning activities on the OCS, to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional security may be required for OCS leases, ROWs and RUEs. This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.

In September 2016, we received notice from the BOEM confirming that we do not qualify to self-insure a portion of any additional financial assurance under NTL #2016-N01. In October 2016, we received from the BOEM proposal letters outlining what additional security the BOEM proposes to require with respect to leases, ROWs and RUEs in which we are designated operator.

In December 2016, the BOEM issued to us an Order to Provide Additional Security for our 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 January 2017, the BOEM, in a notice to stakeholders, extended the implementation timeline for NTL #2016-N01 by an additional six months with respect to non-sole liability properties, except in circumstances in which the BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The extension did not affect the demand to provide financial assurance for leases, ROWs and RUEs constituting sole liability properties.

In February 2017, the BOEM withdrew the orders it issued in December 2016 affecting so called “sole liability properties” to allow time for the new President’s 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 BOEM may 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 liabilities.

As suggested by the BOEM in its January and February notices, 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.

Apache Lawsuit. On December 15, 2014, Apache filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached a JOA related to, among other things, the abandonment of deepwater wells in the Mississippi Canyon area of the Gulf of Mexico. That lawsuit, styled Apache Corporation v. W&T Offshore, Inc., was heard in the United States District Court for the Southern District of Texas. Apache contends that W&T has failed to pay its proportional share of the costs associated with plugging and abandoning three wells that are subject to the JOA. We contend that the costs incurred by Apache are excessive and unreasonable. Apache seeks an award of actual damages, interest, court costs, and attorneys’ fees. In February 2015, we made a payment to Apache for our net share of the amount that we believe was reasonable to plug and abandon the wells.

In November 2016, we filed a motion with the trial court requesting a judgment consistent with the jury’s finding that Apache acted in bad faith thereby causing W&T not to comply with the contract, which W&T asserted bars Apache from recovery for damages under applicable law, and if damages are not barred in their entirety, that any judgment for monetary damages should be offset by $17.0 million as determined by the jury. After Apache filed its opposing motion, a hearing was held by the trial court in December 2016. As of the filing date of this Form 10-K, no judgment has been entered by the court.

Claims against Certain Insurance Companies . In June 2014, the United States Fifth Circuit Court of Appeals reversed a lower court’s ruling in holding that our excess liability policies (“Excess Policies”) cover removal-of-wreck and debris claims arising from Hurricane Ike, even though we exhausted the limits of our Energy Package (defined as certain insurance policies relating to our oil and gas properties which includes named windstorm coverage) with non-removal-of-wreck and debris claims. Several of the insurance companies did not pay us amounts we claim were due under such Excess Policies in accordance with the Fifth Circuit ruling. We filed a lawsuit in September 2014 against certain insurance companies for amounts owed, interest, attorney fees and damages. In December 2016, we entered into settlement agreements with these companies with respect to claims arising from Hurricane Ike which had been made subject to adjustment or request for reimbursement by us, in which these companies agreed to pay such claims totaling $30.2 million, plus interest and attorney fees, which were received in December 2016 and January 2017. This settlement did not include claims arising from Hurricane Ike that have not yet been made subject to adjustment or requested for reimbursement by us.

Monetary Sanctions by Government Authorities. (Notices of Proposed Civil Penalty Assessment) The Company currently has four open civil penalties issued by the BSEE arising from Incidents of Noncompliance (“INCs”) issued by the BSEE, which have not been settled as of the filing of this Form 10-K. The INC’s underlying the civil penalties were issued during 2015 and 2016 and relate to four separate offshore locations with occurrence dates ranging from July 2012 to September 2014. The proposed civil penalties for these INCs total $8.1 million. As of December 31, 2016, the Company has accrued approximately $1.5 million, which is the Company’s best estimate of the final settlement once all appeals have been exhausted. The Company’s position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.

Notification by ONRR of Fine for Non-compliance. In December 2013 and January 2014, we were notified by the 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 (subsequently reduced to approximately $1.1 million) relative to such underpayment. We believe the fine is excessive considering the circumstances and in relation to the amount of underpayment. A hearing on this matter was held with an Administrative Law Judge in August 2016. A decision on this case has been deferred until March 2017 at the earliest. 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, 2016 or 2015, respectively.

Appeal with ONRR. In 2009, the Company recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of deepwater production through our subsea pipeline systems. In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the IBLA. On January 27, 2017, the IBLA affirmed the decision of ONRR requiring W&T to pay approximately $4.7 million in additional royalties plus interest. We are reviewing the decision with counsel to determine an appropriate course of action. We have 180 days to file suit in federal district court for judicial review of final agency action. Based on the date of the IBLA decision, the filing deadline is July 26, 2017.

Iberville School Board Lawsuit. In August 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board, in their suit against the Company (among others) in the 18^th Judicial District Court for the Parish of Iberville, State of Louisiana. This case involves claims by the Iberville Parish School Board that certain property in Louisiana had allegedly been contaminated or otherwise damaged by certain defendants’ oil and gas exploration and production activities. The plaintiff’s claims include assessment costs, restoration costs, diminution of property value, punitive damages, and attorney fees and expenses, of which were not quantified in the claim. The case was set for trial on August 15, 2016, but the trial date has been deferred until early 2017. We cannot currently estimate our potential exposure, if any, related to this lawsuit. We are currently, and intend to continue vigorously defending this litigation.

Other Claims. We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. In addition, the BOEM considers all owners of record title and/or operating rights interest in an OCS lease to be jointly and severally liable for the satisfaction of the financial assurance requirements and/or decommissioning obligations that have accrued to such owners. Accordingly, we may be required to satisfy financial assurance requirements or decommissioning obligations of a defaulting owner of record title and/or operating rights interest in an OCS lease in which we are (or in some cases were) an owner of record title and/or operating rights interest in the same OCS lease. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

See Financial Statements and Supplementary Data - Note 17 – Contingencies under Part II, Item 8 in this Form 10-K for additional information on this matters described above.

Tracy W. Krohn has served as Chief Executive Officer since he founded the Company in 1983 and as Chairman since 2004. He also served as President of the Company until September 2008. During 1996 to 1997, Mr. Krohn was Chairman and Chief Executive Officer of Aviara Energy Corporation. Prior to founding the Company, from 1982 to 1983, Mr. Krohn was a senior engineer with Taylor Energy, and he began his career as a petroleum engineer and offshore drilling supervisor with Mobil Oil Corporation.

Jamie L. Vazquez joined the Company in 1998 as Manager of Land and in 2003 she was named Vice President of Land. In September 2008, Ms. Vazquez was appointed President of the Company. Prior to joining the Company, Ms. Vazquez was with CNG Producing Company for 17 years, holding positions of increasing responsibility ending as Manager, Land/Business Development Gulf of Mexico.

John D. Gibbons joined the Company in February 2007 as Senior Vice President and Chief Financial Officer. Prior to joining the Company, Mr. Gibbons was Senior Vice President and Chief Financial Officer of Westlake Chemical Corporation from March 2006 to February 2007. Prior to joining Westlake, Mr. Gibbons was with Valero Energy Corporation for 23 years, holding positions of increasing responsibility ending as Executive Vice President and Chief Financial Officer.

Thomas P. Murphy joined the Company in June 2012 as Senior Vice President and Chief Operations Officer. From 2009 to 2012, Mr. Murphy worked at Woodside Energy USA Inc. as Vice President Engineering and Operations. From 2008 to 2009 he worked for PetroQuest Energy, Inc. as Vice President Engineering. From 2000 to 2008, Mr. Murphy worked for Devon Energy Corporation in a variety of positions, including Gulf of Mexico Deep-Water Development Supervisor, New Business Development Supervisor and culminating in his position as Sr. Exploration Advisor.

Stephen L. Schroeder joined the Company in 1998 and served as Production Manager from 1999 until 2005. In 2005, Mr. Schroeder was named Vice President of Production and in July 2006 he was named Senior Vice President and Chief Operating Officer. In June 2012, Mr. Schroeder was named Senior Vice President and Chief Technical Officer. Prior to joining the Company, Mr. Schroeder was with Exxon USA for 12 years holding positions of increasing responsibility, ending with Offshore Division Reservoir Engineer.

Thomas F. Getten joined the Company in July 2006 as Vice President, General Counsel and Assistant Secretary. In December 2011, Mr. Getten was appointed to the position of Corporate Secretary. Prior to joining the Company, Mr. Getten served as a partner with King, LeBlanc & Bland, P.L.L.C., a New Orleans law firm, since February 2001. From 1996 to December 2000, Mr. Getten served as Vice President, Secretary and General Counsel of Forcenergy Inc until its merger into Forest Oil Corporation.

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed and principally traded on the NYSE under the symbol “WTI.” The following table sets forth the high and low sales prices of our common stock as reported on the NYSE.

During 2016 and 2015, no dividends were paid as dividend payments have been suspended. Dividends are subject to certain statutory requirements which include positive net equity. Our Board of Directors decides the timing and amounts of any dividends for the Company. Dividends are subject to periodic review of the Company’s performance, which includes the current economic environment and applicable debt agreement restrictions. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 and Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for more information regarding covenants related to dividends in our debt agreements.

The graph below shows the cumulative total shareholder return assuming the investment of $100 in our common stock and the reinvestment of all dividends thereafter. The information contained in the graph below is furnished and not filed, and is not incorporated by reference into any document that incorporates this Annual Report on Form 10-K by reference.

Our peer group is comprised of Apache Corporation, Bill Barrett Corp., Cabot Oil & Gas Corp., Comstock Resources, Inc., Energy XXI (Bermuda) Limited, Newfield Exploration Co., SM Energy Co., SandRidge Energy, Inc., Stone Energy Corp., and Swift Energy Company. Three of the companies in our peer group filed for Chapter 11 reorganization under the U.S. Bankruptcy Code in the last year. The above peer group investment returns assume that common stock investment value in the bankrupt companies was zero in the year in which they filed for bankruptcy.

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K. For descriptions of the plans and additional information, see Financial Statements and Supplementary Data – Note 10 –Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K.

The following table sets forth information about restricted stock units (“RSUs”) delivered by employees during the quarter ended December 31, 2016 to satisfy tax withholding obligations on the vesting of RSUs.

The selected historical financial information set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K.

	Year Ended December 31,
	2016 ⁽¹⁾			2015 ^{(1) (2)}			2014 ⁽³⁾			2013 ⁽⁴⁾			2012 ⁽⁵⁾
	(In thousands, except per share data)
Consolidated Statement of Operations Information:
Revenues:
Oil	$	268,950		$	349,191		$	652,776		$	718,944		$	629,548
NGLs		26,429			27,665			72,837			73,345			84,637
Natural gas		100,405			123,435			217,816			189,290			158,390
Other		4,202			6,974			5,279			2,509			1,916
Total revenues		399,986			507,265			948,708			984,088			874,491
Operating costs and expenses:
Lease operating expenses		152,399			192,765			264,751			270,839			232,260
Production taxes		1,889			3,002			7,932			7,135			5,840
Gathering and transportation		22,928			17,157			19,821			17,510			14,878
Depreciation, depletion and amortization		194,038			373,368			490,469			430,611			336,177
Asset retirement obligations accretion		17,571			20,703			20,633			20,918			20,055
Ceiling test write-down of oil and natural gas properties ⁽⁶⁾		279,063			987,238			—			—			—
General and administrative expenses		59,740			73,110			86,999			81,874			82,017
Derivative (gain) loss		2,926			(14,375	)		(3,965	)		8,470			13,954
Total costs and expenses		730,554			1,652,968			886,640			837,357			705,181
Operating income (loss)		(330,568	)		(1,145,703	)		62,068			146,731			169,310
Interest expense, net of amounts capitalized		92,271			97,336			78,396			75,581			49,994
Gain on exchange of debt ⁽⁷⁾		123,923			—			—			—			—
Other (income) expense, net ⁽⁸⁾		(6,520	)		4,663			(208	)		(8,946	)		(215	)
Income (loss) before income tax expense (benefit)		(292,396	)		(1,247,702	)		(16,120	)		80,096			119,531
Income tax expense (benefit)		(43,376	)		(202,984	)		(4,459	)		28,774			47,547
Net income (loss)	$	(249,020	)	$	(1,044,718	)	$	(11,661	)	$	51,322		$	71,984
Basic and diluted earnings (loss) per common share	$	(2.60	)	$	(13.76	)	$	(0.16	)	$	0.68		$	0.95
Dividends on common stock ⁽⁹⁾		—			—			30,260			58,846			82,832
Cash dividends per common share		—			—			0.40			0.78			1.11
Consolidated Cash Flow Information:
Net cash providing by operating activities ⁽¹⁰⁾	$	14,180		$	133,228		$	474,821		$	562,708		$	358,353
Capital expenditures - oil and natural gas properties ⁽¹¹⁾		48,606			230,161			626,612			634,378			684,863

The following tables present summary information regarding our estimated net proved oil, NGLs and natural gas reserves and our historical operating data for the years shown below. Estimated net proved reserves are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December of the respective year in accordance with SEC guidelines. For additional information regarding our estimated proved reserves, please read Business under Part I, Item 1 and Properties under Part I, Item 2 of this Form 10-K. The selected historical operating data set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K.

	December 31,
	2016			2015			2014			2013			2012
Reserve Data: ⁽¹⁾
Estimated net proved reserves
Oil (MMBbls)		32.9			35.5			61.7			58.5			54.8
NGLs (MMBbls)		8.2			6.6			15.8			15.9			15.2
Natural Gas (Bcf)		197.8			205.4			254.9			259.9			285.1
Total barrel equivalents (MMBoe)		74.0			76.4			120.0			117.7			117.5
Total natural gas equivalents (Bcfe)		444.0			458.1			720.0			705.9			705.1
Proved developed producing (MMBoe)		47.3			57.6			68.7			60.6			62.6
Proved developed non-producing (MMBoe)		17.4			11.4			14.6			25.5			24.3
Total proved developed (MMBoe)		64.7			69.0			83.3			86.1			86.9
Proved undeveloped (MMBoe)		9.3			7.4			36.7			31.6			30.6
Proved developed reserves as %		87.4	%		90.3	%		69.4	%		73.2	%		74.0	%
Reserve additions (reductions) (MMBoe):
Revisions ⁽²⁾		13.0			(12.7	)		4.1			(3.9	)		(4.7	)
Extensions and discoveries		—			4.1			9.7			20.2			15.8
Purchases of minerals in place		—			1.0			6.1			2.4			7.0
Sales of minerals in place ⁽³⁾		—			(19.0	)		—			(0.5	)		(0.4	)
Production		(15.4	)		(17.0	)		(17.6	)		(18.0	)		(17.1	)
Net reserve additions (reductions)		(2.4	)		(43.6	)		2.3			0.2			0.6

	Year Ended December 31,
	2016		2015		2014		2013 ⁽¹⁾		2012
Operating: ⁽²⁾
Net sales:
Oil (MBbls)		7,201		7,751		7,176		7,018		6,033
NGLs (MBbls)		1,542		1,604		2,112		2,091		2,129
Oil and NGLs (MBbls)		8,743		9,355		9,288		9,110		8,163
Natural gas (MMcf)		39,731		46,163		50,088		53,257		53,825
Total oil equivalent (MBoe)		15,365		17,049		17,636		17,986		17,133
Total natural gas equivalents (MMcfe)		92,188		102,294		105,815		107,915		102,800
Average daily equivalent sales (Boe/day)		41,980		46,709		48,317		49,276		46,813
Average daily equivalent sales (Mcfe/day)		251,879		280,256		289,904		295,657		280,875
Average realized sales prices:
Oil ($/Bbl)	$	37.35	$	45.05	$	90.96	$	102.44	$	104.35
NGLs ($/Bbl)		17.14		17.25		34.49		35.07		39.75
Oil and NGLs ($/Bbl)		33.79		40.28		78.13		86.97		87.50
Natural gas ($/Mcf)		2.53		2.67		4.35		3.55		2.94
Oil equivalent ($/Boe)		25.76		29.34		53.49		54.58		50.93
Natural gas equivalent ($/Mcfe)		4.29		4.89		8.92		9.10		8.49
Average per Boe ($/Boe):
Lease operating expenses	$	9.92	$	11.31	$	15.01	$	15.06	$	13.56
Gathering and transportation		1.49		1.01		1.14		0.95		0.85
Production costs		11.41		12.32		16.15		16.01		14.41
Production taxes		0.12		0.17		0.42		0.42		0.36
DD&A		13.77		23.11		28.98		25.10		20.79
General and administrative expenses		3.89		4.29		4.93		4.55		4.79
	$	29.19	$	39.89	$	50.48	$	46.08	$	40.35
Average per Mcfe ($/Mcfe):
Lease operating expenses	$	1.65	$	1.88	$	2.50	$	2.51	$	2.26
Gathering and transportation		0.25		0.17		0.19		0.16		0.14
Production costs		1.90		2.05		2.69		2.67		2.40
Production taxes		0.02		0.03		0.07		0.07		0.06
DD&A		2.30		3.85		4.83		4.18		3.47
General and administrative expenses		0.65		0.71		0.82		0.76		0.80
	$	4.87	$	6.64	$	8.41	$	7.68	$	6.73
Wells drilled (gross):
Offshore		1		5		6		6		5
Onshore		—		5		33		40		77
Productive wells drilled (gross):
Offshore		1		5		6		5		4
Onshore		—		5		33		40		77

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Risk Factors under Part I, Item 1A in this Form 10-K.

We are an independent oil and natural gas producer with operations offshore in the Gulf of Mexico. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 52 offshore fields in federal and state waters (50 producing and two fields capable of producing). We currently have under lease approximately 750,000 gross acres, with approximately 490,000 gross acres on the shelf and approximately 260,000 gross acres in the deepwater. A majority of our daily production is derived from wells we operate offshore. We own interests in approximately 164 offshore structures, 107 of which are located in fields that we operate. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy VI, LLC.

In managing our business, we are focused on maintaining and growing production and reserves in a profitable and prudent manner. We have historically grown our reserves and production through acquisitions and our drilling programs. With respect to acquisitions, we have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition. Starting in mid-2014, commodity prices began to fall and continued falling during 2015 and 2016. Towards the end of 2016 and during the first quarter of 2017, prices have recovered some from average realized prices during 2016, but are still well below 2014 levels. Although our operating costs have also fallen during this time frame, our margins as a percentage of revenue have not recovered to the levels prior to 2015. In reaction to the significant downturns during 2016 and 2015, we did not consummate any acquisitions of significance, we reduced our capital expenditures and we sold our interest in the Yellow Rose field discussed below. Our plans for the short-term include operating within cash flow, maintaining liquidity, meeting our financial obligations, and pursuing acquisitions meeting our criteria.

Our drilling efforts in recent years have expanded in the deepwater of the Gulf of Mexico. During 2016, our volumes included production from the deepwater fields, Big Bend and Dantzler, which commenced production in late 2015. As of December 31, 2016, both fields were in our top ten fields based on reserves, net to our interest, on a Boe basis. Both fields are composed of mostly oil and NGLs, having over 75% of reserves in oil and NGLs on a Boe basis.

In September 2016, we consummated the Exchange Transaction whereby we exchanged approximately $710.2 million principal amount, or 79%, of our Unsecured Senior Notes for $301.8 million principal amount of new secured notes and 60.4 million shares of our common stock, and closed on a new $75.0 million 1.5 Lien Term Loan. The funds from the 1.5 Lien Term Loan were used to partially pay down borrowings outstanding on the revolving bank credit facility and to pay transaction costs associated with the Exchange Transaction. See the Liquidity and Capital Resources section of this Item 7, and 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.

In October 2015, we sold our interests in the Yellow Rose onshore field in the Permian Basin to Ajax. Our interest in the field covered approximately 25,800 net acres. During 2015, the Yellow Rose field accounted for approximately 5% and 6% of our production and revenues, respectively. In connection with the sale, we retained a non-expense bearing ORRI equal to a variable percentage in production from the working interests sold, which percentage varies on a sliding scale from one percent for each month that the prompt month 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. Internal estimates of proved reserves at the date of the sale were 19.0 MMBoe, consisting of approximately 71% oil, 11% NGL and 18% natural gas. Including adjustments from an effective date of January 1, 2015, the adjusted sales price was $370.9 million and the buyer assumed the ARO associated with our interests in the Yellow Rose field, which we had estimated at $6.9 million at the time of the sale. We used a portion of the proceeds of the sale to repay all the outstanding borrowings under our revolving bank credit facility, while the remaining balance of approximately $100 million was added to available cash.

In September 2014, we acquired an additional ownership interest in the Fairway Field (Mobile Bay blocks 113 and 132) located in Alabama state waters and the associated Yellowhammer gas processing plant, which increased our ownership interest from 64.3% to 100%. Including adjustments from an effective date of July 1, 2014, the adjusted purchase price was $17.4 million and we assumed the additional ARO associated with the increased ownership interest in Fairway, which we have estimated to be $6.1 million. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

In May 2014, we acquired from Woodside 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. Including adjustments from an effective date of November 1, 2013, the adjusted purchase price was $54.8 million and we assumed the ARO associated with the Woodside Properties, which we have estimated to be $11.3 million. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

See Financial Statements and Supplementary Data – Note 7 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information on acquisitions and divestitures.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for 2016 were comprised of approximately 47% oil and condensate, 10% NGLs and 43% natural gas, determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs. The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices per Mcfe for crude oil, NGLs and natural gas may differ significantly. For 2016, our combined total production of oil, NGLs and natural gas was 9.9% below 2015, primarily due to natural production declines and divestiture of the Yellow Rose properties, partially offset by production from the Big Bend and Dantzler fields, which began production in the fourth quarter of 2015, and from one well completed during the year at our Ewing Bank 910 field.

Our realized sales prices received for our crude oil, NGLs and natural gas production are affected by not only domestic production activities and political issues, but more importantly, international events, including both geopolitical and economic events. During 2016 and 2015, crude oil, NGL, and natural gas realized prices were significantly below prior year prices. Thus far in 2017, prices have recovered some and have been higher than the average prices occurring during 2016. Partially offsetting the declining sales prices has been a reduction in the cost of supplier goods and services in 2016 and 2015 compared to 2014, but these have not decreased as quickly and dramatically as the price of the commodities that we sell; therefore, margins deteriorated significantly in 2016 and 2015 along with total cash flows. The current market imbalance is predominantly supply driven caused by a number of issues that are described below.

The U.S. Energy Information Administration’s (“EIA”) data estimates the worldwide supply of crude oil and other petroleum liquids outpaced consumption in 2016 by 0.9 million barrels per day in addition to an oversupply in 2015 by 1.8 million barrels per day. This was the third consecutive year that inventories had built and exerted downward pressure on prices. For 2017 and 2018, EIA forecasts crude oil supply being above consumption by approximately 0.3 million barrels per day and 0.2 million barrels per day, respectively. Currently, EIA estimates inventory builds in the first two quarters of 2017, inventory usage in the third quarter of 2017, and an inventory build in the fourth quarter of 2017. The high levels of excess inventory will likely exert downward pressure on prices in the near future. Worldwide crude oil supply growth in 2016 from 2015 was estimated at 0.7%, while consumption growth was estimated at 1.6%. The increases in production were primarily from OPEC, with Iran, Iraq and Saudi Arabia having the largest increases. The forecast assumes the November 2016 OPEC production target agreement will be largely adhered to by the countries within OPEC. EIA forecasts supply increases in 2017 and 2018 of 1.1% and 1.4%, respectively, year over year. EIA estimates consumption growing for most countries, except for Japan and Canada.

According to data provided by EIA, U.S. production of crude oil (excluding other petroleum liquids) decreased in 2016 by 6% compared to 2015. EIA’s estimate for 2017 and 2018 of U.S. crude oil production is an increase of 1.2% and 3.3%, respectively, year over year. As noted below, the number of rigs drilling for oil decreased dramatically in 2015 and further decreased through most of 2016, and began to increase in the fourth quarter of 2016 and the first quarter of 2017.

During 2016, our average realized crude oil sales price was $37.35, down from $45.05 per barrel (17.1% lower) for 2015. The two primary benchmarks reported upon are the prices for WTI and Brent crude oil. As reported by the EIA, WTI crude oil prices averaged $43.29 per barrel for 2016, down from $48.66 per barrel (11.0% lower) for 2015. Brent crude average oil prices decreased to $43.67 per barrel for 2016, down from $52.32 per barrel (16.5% lower) for 2015. WTI and Brent average crude oil prices in the fourth quarter of 2016 were higher than the prior three quarters of 2016 presenting an upward trend in crude oil prices. For 2016, WTI and Brent average prices were basically at parity. Our average realized oil sales price ($37.35 per barrel compared to a WTI benchmark price of $43.29 per barrel) for 2016 differs from the benchmark crude prices due to premiums or discounts (referred to as differentials), crude quality adjustments, volume weighting and other factors. All of our oil during 2016 was produced offshore in the Gulf of Mexico and is characterized as Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”), Poseidon and others. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility. For example, the monthly average differentials of WTI versus LLS, HLS and Poseidon for 2016 were a positive $1.70 and $0.84, and a negative $3.57 per barrel, respectively, compared to positive $3.72 and $2.76, and a negative $1.04 per barrel, respectively, for 2015. The majority of our crude oil is priced similar to Poseidon and, therefore, is experiencing negative differentials. In addition, a few of our crude oil fields have a negative quality bank adjustment as the crude quality (as per American Petroleum Institute’s gravity and sulfur content measurement) is below the standard crude oil quality for the pipeline.

An EIA report issued in early January 2017 projected WTI crude oil prices for 2017 and 2018 at $52.50 per barrel and $55.18 per barrel, respectively, and Brent crude oil prices for 2017 and 2018 at $53.50 per barrel and $56.18, respectively.

During 2016, our average realized NGLs sales price decreased 0.6% compared to 2015. Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. During 2016, average prices for domestic ethane increased 12% and average domestic propane prices increased 7% from 2015. Average price changes for other domestic NGLs were a decrease of 12% to an increase of 12% between 2016 and 2015. Per EIA, production of ethane and propane increased in 2016 over 2015 by 11% and 2%, respectively. Ethane inventories at year end were much higher than the prior year, increasing 49%, and although ethane prices have increased from prior year levels, ethane prices remain low compared to historical levels. Propane inventory levels at year end were also much higher going into the heating season and are 27% higher than at year end 2015. As long as ethane and propane inventories remain high, the possibility of a price recovery is unlikely. As long as the price ratio of crude oil to natural gas remains wide (as measured on a six to one energy equivalency), the production of NGLs may continue to be high relative to historical norms, which would in turn suggest continued weak prices, or possibly further price reductions, especially for the prices of ethane and propane. Many natural gas processing facilities have been and from time to time, will likely continue re-injecting ethane back into the natural gas stream after processing due to insufficient ethane demand, which negatively impacts production and natural gas prices. Ethane demand is expected to increase in 2017 as petrochemical plants and expansion projects that consume ethane come online.

During 2016, our average realized natural gas sales price decreased 5.2% compared to 2015. According to the EIA, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 3.8% lower in 2016 from 2015. Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues, other fuel competition (coal) and domestic economic conditions, and they have historically been subject to substantial fluctuation. However, with the surplus of natural gas that has plagued the industry since 2012, natural gas prices have been weak and the fluctuations in prices have been limited to the lower end of the price range. Prices in the fourth quarter of 2016 were above the previous three quarters, representing an upward trend, but price levels continue to be very weak. Per EIA, the increase was attributable to higher demand for electricity generation in the summer and declining production. The U.S. natural gas inventories at the end of 2016 were approximately 10% lower than a year earlier and 2% lower than the five year average. U.S. consumption was flat during 2016, with commercial electricity consumption increases offsetting decreases in residential usage. U.S. supplies decreased 3% due primarily to slightly lower production in the lower 48 states.

The average price of natural gas is still weak from an overall economic standpoint, and we expect continued weakness in natural gas prices for a number of reasons, including (i) producers may continue to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) production efficiency gains being achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling, pad drilling and production techniques and (iii) re-injecting ethane into the natural gas stream as indicated above, which increases the natural gas supply.

EIA projects natural gas prices to increase in 2017 compared to 2016, and then to increase further in 2018. Price increases will likely be relatively minor as natural gas production can ramp up relatively quickly. U.S. production is projected to be about flat for 2017 compared to 2016, then to rise by 2% in 2018. Natural gas usage for power generation is expected to be between 32% and 33% in 2017 and 2018, compared to 34% in 2016 and 33% in 2015 due to higher natural gas prices compared to coal.

During most of 2016, the number of rigs drilling for oil and natural gas in the U.S. was down significantly from 2014 levels. Rig counts increased during the fourth quarter of 2016 and are approaching 2015 levels. According to Baker Hughes, the oil rig count at the end of 2014, 2015 and 2016 was 1,482, 536 and 525, respectively. During 2016, the oil rig count low was 316 and the high was 525. The U.S. natural gas rig count at the end of 2014, 2015 and 2016 was 328, 162, and 132, respectively. During 2016, the gas rig count low was 81 and the high was 148. In the Gulf of Mexico, there were 54 rigs (42 oil and 12 natural gas) at the end of 2014, 25 rigs (20 oil and five natural gas) at the end of 2015, and 22 rigs (22 oil and no natural gas) at the end of 2016. The majority of rigs in the Gulf of Mexico are currently “floaters” rather than jack-up rigs.

As required by the full cost accounting rules, we perform our ceiling test calculation each quarter using the SEC pricing guidelines, which require using the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price adjusted for price differentials. The average price using the SEC required methodology at December 31, 2016 was $39.25 per barrel for WTI crude oil and $2.48 per MMBtu for Henry Hub natural gas before adjustments. Due to the decrease in the 12-month average price for both crude oil and natural gas during 2016, we recorded ceiling test write-downs of the carrying value of our oil and natural gas properties in the first three quarters of 2016 totaling $279.1 million, but did not have a write-down during the fourth quarter of 2016. For 2015, we recorded ceiling test write-downs in each quarter totaling $987.2 million for the full year. Incurrence of further write downs is dependent primarily on the price of crude oil and natural gas, but also is affected by quantities of proved reserves, future development costs and future lease operating costs.

We performed a pro-forma calculation to determine if a further ceiling test impairment write-down would be likely in the first quarter of 2017 based only on changes to prices available during the first quarter of 2017. In this pro-forma calculation, no changes were assumed for proved reserves from the December 31, 2016 levels other than price and no changes were assumed for other factors. The pro-forma calculation indicated we would not incur a ceiling-test write-down in the first quarter of 2017 basely solely on a change in price. This pro-forma calculation may not be predictive of the first quarter of 2017, as other factors besides price will impact the ceiling test calculation.

See Properties – Proved Reserves under Part I, Item 2; Selected Financial Data under Part II, Item 6 and Financial Statements and Supplementary Data – Note 21 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for additional information on our proved reserves.

As of December 31, 2016, we had $70.2 million of available cash and $149.5 million available on our revolving bank credit facility. See the Liquidity and Capital Resources section of this Item 7, and Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for a description of our debt structure.

As to financial assurances for decommissioning obligations, in December 2016, the BOEM issued to us an Order to Provide Additional Security for our sole liability properties. In January 2017, the BOEM granted an extension of six months related to NTL #2016-N01 for leases, ROWs and RUEs that are non-sole liability properties. In February 2017, the BOEM withdrew the sole liability order it had issued to us in December 2016 to allow time for the new President’s administration to review the complex financial assurance program. Any implementation issues associated with those orders will be discussed as part of the January 2017 Extension that the BOEM initiated to gather input on other components of the NTL #2016-N01. See Liquidity and Capital Resources in this Item 7 in this Form 10-K for additional information concerning these financial assurances, our liquidity and other financial obligations. In addition, see Risk Factors under Part I, Item 1A for risks related to our financial obligations.

Many changes in laws, regulations, guidance, interpretations and policy continue to be proposed and issued in our industry. At this time, we are unable to assess the potential impact as clarification is needed for items within the proposals.

Due to the sustained lower commodity price environment and the outlook for the remainder of 2017, we have set our 2017 capital expenditure budget at $125 million, which excludes potential acquisitions. Although this is an increase from the $49 million capital expenditures incurred in 2016, our current plan for 2017 is a significant reduction from 2015 and 2014 investment levels of $231 million and $630 million, respectively. We have the flexibility to make this reduction to our 2017 capital expenditure budget because we have no long term rig commitments and no pressure from co-owners to drill or complete a well. The Ewing Bank 910 A-8 well began production during 2016 and the SS 349/359 (Mahogany) A-18 well was completed and begin production during the first quarter of 2017. Some of our expenditures planned for 2017 are expected to impact production for 2017, while most are expected to impact 2018 production and beyond. 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 plans include spending $78.3 million in 2017 for ARO (discussed in more detail below), compared to $72.3 million spent on ARO in 2016. We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans. See Risk Factors under Part I, Item 1A in this Form 10-K for additional information.

Our operating costs in 2016 included the expense of operating our wells, platforms and other infrastructure primarily in the Gulf of Mexico, and transporting our production to the points of sale. During 2016, our lease operating expenses decreased approximately 12.3% compared to 2015 on a per Boe basis. Our operating costs were lower in 2016 compared to 2015 primarily due to lower costs of goods and services from vendors combined with the sale of the Yellow Rose field in October 2015. Partially offsetting were higher operating costs for the Big Bend and Dantzler fields, which began production in the fourth quarter of 2015, and lower product handling arrangement (“PHA”) fees for the Matterhorn field. Our operating costs are generally comprised of several components, including direct operating costs, repairs and maintenance, gathering and transportation costs, production taxes, insurance premiums, workover costs and ad valorem taxes. Our operating costs depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties. Workover costs can vary significantly from year to year depending on the level of activity (either required or desired) and type of equipment used. In those instances where a drilling rig is required as opposed to some other type of intervention vessel or equipment, the costs tend to be much higher and require more time.

In recent years, we have operated or participated in wells near the outer edge of the continental shelf and in the deepwater of the Gulf of Mexico. To the extent we continue expanding deepwater operations, our operating costs may increase, especially as we find and produce more crude oil rather than natural gas. While each field can present operating complexities that can add to the costs of operating a field, the production costs of a field are generally directly proportional to the number of production platforms built in the field. As technologies have improved, oil and natural gas can be produced from larger acreage areas using a single platform, which may reduce the operating costs associated with future development projects.

Our offshore operations are exposed to potential damage from hurricanes and normally we obtain insurance to reduce, but not totally mitigate, our financial exposure risk. See Liquidity and Capital Resources - Hurricane Remediation, Insurance Claims and Insurance Coverage under this Item 7 in this Form 10-K for additional information.

Applicable environmental regulations require us to remove our platforms after production has ceased, to plug and abandon all wells and to remediate any environmental damage our operations may have caused. These types of activities are collectively referred to as decommissioning or ARO. The costs per well associated with our ARO generally increase as we drill wells in deeper parts of the continental shelf and in the deepwater. We generally do not pre-fund our ARO, but have obtained approximately $300 million in bonds and have restricted deposits for certain ARO arrangements. Over the last ten years, we have spent over $700 million for ARO. We estimated the present value of our liability related to our ARO at $334.4 million as of December 31, 2016, of which $78.3 million is estimated to be spent during 2017. Inherent in the present value calculation of our liability are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and expenditure, and changes in the legal, regulatory, environmental and political environments. Actual expenditures for ARO could vary significantly from these estimates and have varied significantly in the past. Prior to 2015, we saw upward revisions in costs to do this work partly due to significant changes in the regulatory requirements and partly due to the escalation in the cost of goods and services required to do the work. The increase in oil prices that occurred over several years before the decline that began in June 2014 led to significant cost inflation of goods and services in the Gulf of Mexico and other producing basins. During 2015 and 2016, most of the plug and abandonment service costs trended lower, although some costs increased due to scope changes and regulatory interpretation changes. Overall, service costs related to plugging and abandonment were relatively lower in 2016 compared to 2015 on a per project basis.

Many changes in laws, regulations, guidance, interpretations and policy continue to be proposed and issued in our industry. The process for obtaining offshore drilling permits, especially deepwater drilling permits, has expanded and lengthened in the past few years. The most significant regulatory changes in recent years are NTL #2016-N01 and interpretations related to unbundling costs at natural gas plants, which adversely impact royalty payments. In addition, regulations have expanded related to potential environmental impacts, spill response documentation, compliance reviews and operator practices related to safety and environmental matters. This has led to higher costs for revisions, training, implementations and monitoring related to our safety and environmental management systems. The new regulations and increased review process increases the time to obtain drilling permits and increases the cost of operations. Also, the regulations have changed related to plugging and abandonment of offshore wells and related infrastructure considerably, driving up both the time and cost to perform the work. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time. See Business - Regulation under Part I, Item 1 in this Form 10-K for additional information.

Revenues. Total revenues decreased $107.3 million, or 21.1%, to $400.0 million in 2016 compared to 2015. Oil revenues decreased $80.2 million, or 23.0%, NGLs revenues decreased $1.2 million, or 4.5%, natural gas revenues decreased $23.0 million, or 18.7%, and other revenues decreased $2.8 million. The oil revenue decrease was attributable to a 17.1% per barrel decrease in the average realized sales price to $37.35 per barrel in 2016 from $45.05 per barrel in 2015 and a 7.1% decrease in sales volumes. The NGLs revenue decrease was attributable to a 0.6% decrease in the average realized sales price to $17.14 per barrel in 2016 from $17.25 per barrel in 2015 and a decrease of 3.9% in sales volumes. The decrease in natural gas revenue was attributable to a 5.2% decrease in the average realized natural gas sales price to $2.53 per Mcf in 2016 from $2.67 per Mcf for 2015 and a 13.9% decrease in sales volumes. We experienced increases in production at the Big Bend and Dantzler fields, which began production in the fourth quarter of 2015. Also, production increases were achieved at the Ewing Bank 910 field, the Main Pass 108, the Main Pass 98 field and the East Cameron 321 field. Offsetting these production increases were production declines primarily from the sale of the Yellow Rose field in October 2015 (0.8 MMBoe); decreases at Mahogany, Matterhorn and Garden Banks 302 (Power Play) and other fields due to natural production declines; and various operational issues. Production deferrals, which occurred at Mahogany and other locations, were attributable to third-party pipeline outages, operational issues, and maintenance. For 2016, we estimate that production deferrals were 1.4 MMBoe compared to 1.8 MMBoe for 2015.

Revenues from oil and liquids as a percent of our total revenues were 73.8% for 2016 compared to 74.3% for 2015. NGLs realized sales prices as a percent of crude oil realized prices increased to 45.9% for 2016 compared to 38.3% for 2015 as crude oil prices continued to decline during most of 2016.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, decreased $40.4 million, or 20.9%, to $152.4 million in 2016 compared to 2015. On a per Boe basis, lease operating expenses decreased to $9.92 per Boe during 2016 compared to $11.31 per Boe during 2015. On a component basis, base lease operating expenses decreased $18.1 million, workover expense decreased $12.6 million, insurance premiums decreased $6.6 million, facilities maintenance decreased $2.1 million and insurance reimbursements increased $1.0 million (offset to expense). Base lease operating expenses decreased primarily due to lower costs from service providers and elimination of field expenses related to the sale of the Yellow Rose field, which was sold in October 2015; partially offset by increases in expenses related to our new deepwater fields at Dantzler and Big Bend; and lower PHA fees (cost offsets) at our Matterhorn field. The decrease in workover costs was primarily due to the sale of the Yellow Rose field and various activities that occurred in 2015 that did not reoccur in 2016. Insurance premium reductions are primarily due to revisions in the Energy Package related to named windstorms coverage.

Production taxes. Production taxes decreased to $1.9 million, or 37.1%, during 2016 compared to $3.0 million in 2015 primarily due to lower commodity prices and the sale of the Yellow Rose field. Currently, production taxes are not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes, while onshore and state water operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs increased to $22.9 million, or 33.6%, in 2016 compared to $17.2 million in 2015 primarily due to production increases from the Big Bend and Dantzler fields, both of which began producing in the fourth quarter of 2015.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $13.77 per Boe for 2016 from $23.11 per Boe for 2015. On a nominal basis, DD&A decreased to $211.6 million, or 46.3%, for 2016 from $394.1 million in 2015. DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during 2016 and 2015, and lower capital expenditures in relation to DD&A expense, which lowers the full-cost pool subject to DD&A. In addition, the proceeds from the sale of our Yellow Rose field reduced the full cost pool along with the removal of future development costs associated with the Yellow Rose field proved reserves. Other factors affecting the DD&A rate are changes to future development costs on remaining proved reserves and changes to proved reserves.

Ceiling test write-down of oil and natural gas properties. For 2016 and 2015, we recorded non-cash ceiling test write-downs of $279.1 million and $987.2 million, respectively, as the book value of our oil and natural gas properties exceeded the ceiling test limitation. The write-down is the result of decreases in prices for all three commodities we sell, which are crude oil, NGLs and natural gas. See Financial Statements and Supplementary Data – Note 1 - Basis of Presentation under Part II, Item 8 in this Form 10-K, which provides a description of the ceiling test limit determination, and above under the section Overview in this Item regarding our prospects for a future significant ceiling test write-downs.

General and administrative expenses (“G&A”). G&A decreased to $59.7 million, or 18.3%, for 2016 from $73.1 million for 2015 primarily due to decreases in headcount related expense (salaries, benefits, and contractor expenses), elimination of certain employee benefits, increased reimbursements from stop-loss medical policies, and reductions in legal settlements, partially offset by higher legal costs. G&A on a per BOE basis was $3.89 Boe for 2016 compared to $4.29 per Boe for 2015. See Financial Statements and Supplementary Data – Note 10 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K for additional information.

Derivative net gain. For 2016, there was a $2.9 million derivative net loss recorded for derivative contracts for crude oil and natural gas. As of December 31, 2016, we do not have any open derivative contracts. We entered into derivative contracts for crude oil and natural gas during the second quarter of 2015, relating to 2015 and 2016 estimated production. For 2015, there was a $14.4 million derivative net gain recorded for derivative contracts for crude oil and natural gas. For both periods, the amount includes changes in the fair value of commodity derivative contracts. See Financial Statements and Supplementary Data – Note 8 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

Interest expense. Interest expense incurred was $92.8 million in 2016, compared to $104.6 million in 2015. The decrease was primarily attributable to the Exchange Transaction. Interest expense was reduced for the Unsecured Senior Notes exchanged on September 7, 2016. For the debt issued in the Exchange Transaction, undiscounted future cash flows (principal, PIK and cash interest) are recorded as part of the carrying value of the debt under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”); therefore, no interest expense was recorded for the debt issued in the Exchange Transaction for the period of September 7, 2016 to December 31, 2016. In addition, interest expense was lower due to lower average borrowings on the revolving bank credit facility. During 2016 and 2015, interest of $0.5 million and $7.3 million, respectively, was capitalized to unevaluated oil and natural gas properties. The decrease is primarily attributable to the sale of the Yellow Rose field during the fourth quarter of 2015 and reclassifying all other remaining unevaluated properties to the full-cost pool during 2016.

Gain on exchange of debt. A gain of $123.9 million was recorded related to the Exchange Transaction. Under ASC 470-60, a gain was recognized as undiscounted future cash flows of the debt issued in the Exchange Transaction, plus the fair value of the common stock issued and deal transaction costs were less than the sum of the carrying value of the Unsecured Senior Notes exchanged combined with the funds received from the 1.5 Lien Term Loan issued. See Liquidity and Capital Resources in this Item for a table on the calculation of the gain.

Other (income) expense, net. Other (income) expense, net was income of $6.5 million in 2016 and was an expense of $4.7 million for 2015. For 2016, $7.7 million of income was recorded related to the settlements with certain insurance companies. In both 2016 and 2015, write-downs of unamortized debt issuance costs were recorded related to a reduction in the borrowing base on the revolving bank credit facility. The reductions in the borrowing base resulted in proportional reductions in 2016 and 2015 of $1.4 million and $3.2 million, respectively, in the unamortized debt issuance costs related to the revolving bank credit facility. In addition, during 2015, a net loss on sale of assets of $1.0 million was recorded primarily related to the sale of computer equipment used for backup processes.

Income tax benefit. Our income tax benefit for 2016 and 2015 was $43.4 million and $203.0 million, respectively, with the change attributable primarily to the deferred tax assets and the valuation allowance recorded for the respective periods. Our annualized effective tax rate for 2016 and 2015 was 14.8% and 16.3%, respectively, and differs from the federal statutory rate of 35% primarily due to the valuation allowances recorded for our deferred tax assets in both periods. During 2016 and 2015, we recorded increases to the valuation allowance of $52.9 million and $232.9 million, respectively, related to federal and state deferred tax assets. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. See Financial Statements and Supplementary Data – Note 12 – Income Taxes under Part II, Item 8 in this Form 10-K for additional information.

Revenues. Total revenues decreased $441.4 million, or 46.5%, to $507.3 million in 2015 compared to 2014. Oil revenues decreased $303.6 million, or 46.5%, NGLs revenues decreased $45.2 million, or 62.0%, natural gas revenues decreased $94.4 million, or 43.3%, and other revenues increased $1.7 million. The oil revenue decrease was attributable to a 50.5% per barrel decrease in the average realized sales price to $45.05 per barrel in 2015 from $90.96 per barrel in 2014, partially offset by an 8.0% increase in sales volumes. The NGLs revenue decrease was attributable to a 50.0% decrease in the average realized sales price to $17.25 per barrel in 2015 from $34.49 per barrel in 2014 and a decrease of 24.1% in sales volumes. The decrease in natural gas revenue was attributable to a 38.6% decrease in the average realized natural gas sales price to $2.67 per Mcf in 2015 from $4.35 per Mcf for 2014 and a 7.8% decrease in sales volumes. We experienced increases in production at Mahogany; Mississippi Canyon 582 (Medusa); Mississippi Canyon 506 (Wrigley) field; Atwater Valley 575 field (Neptune); Brazos A133 field (partially due to the acquisition of an additional working interest); and Dantzler and Big Bend, which began production in the fourth quarter of 2015. Production was negatively impacted for all commodities from natural production declines, production deferrals affecting various fields and the divestiture of the Yellow Rose field.

Revenues from oil and liquids as a percent of our total revenues were 74.3% for 2015 compared to 76.5% for 2014. NGLs realized sales prices as a percent of crude oil realized prices increased to 38.3% for 2015 compared to 37.9% for 2014.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, decreased $72.0 million, or 27.2%, to $192.8 million in 2015 compared to 2014. On a per Boe basis, lease operating expenses decreased to $11.31 per Boe during 2015 compared to $15.01 per Boe during 2014. On a component basis, workover expense decreased $26.0 million, base lease operating expenses decreased $24.5 million, facilities maintenance decreased $17.3 million and insurance premiums decreased $4.9 million. The decrease in workover costs was primarily due to reductions in onshore activity and offshore activity at High Island 111 in 2014. Base lease operating expenses decreased primarily due to lower cost from service providers, less onshore downhole well work and the sale of the Yellow Rose field, partially offset by increases from acquisitions, lower production handling fees, expenses related to our new deepwater fields at Dantzler and Big Bend, and expenses related to our new well at Ewing Banks 910.

Production taxes. Production taxes decreased to $3.0 million, or 62.2%, during 2015 compared to $7.9 million in 2014 primarily due to lower commodity prices and the sale of the Yellow Rose field. Currently, production taxes are not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes, while onshore and state water operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs decreased to $17.2 million, or 13.4%, in 2015 compared to $19.8 million in 2014 primarily due to reductions related to transactions with the Terrebonne gas processing plant.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $23.11 per Boe for 2015 from $28.98 per Boe for 2014. On a nominal basis, DD&A decreased to $394.1 million, or 22.9%, for 2015 from $511.1 million in 2014. DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during the first three quarters of 2015 (the fourth quarter ceiling test write-down will affect the DD&A rate starting with the first quarter of 2016) and lower capital expenditures in relation to DD&A expense, which lowers the full-cost pool subject to DD&A. In addition, the proceeds from the sale of our Yellow Rose field reduced the full cost pool along with the removal of future development costs associated with the Yellow Rose field reserves. Additional factors affecting the DD&A rate are lower future development costs on remaining reserves and lower proved reserves.

Ceiling test write-down of oil and natural gas properties. For 2015, we recorded a non-cash ceiling test write-down of $32.4 million in the fourth quarter of 2015 and $987.2 million for the full year as the book value of our oil and natural gas properties exceeded the ceiling test limitation. The write-down is the result of decreases in prices for all three commodities we sell, which are crude oil, NGLs and natural gas. No ceiling test write-down was recorded in 2014. See Financial Statements and Supplementary Data – Note 1 - Basis of Presentation under Part II, Item 8 in this Form 10-K, which provides a description of the ceiling test limit determination.

General and administrative expenses. G&A decreased to $73.1 million, or 16.0%, for 2015 from $87.0 million for 2014 primarily due to decreases in incentive compensation, a significant decrease in the use of contractors and much lower share-based compensation, partially offset by lower billings to joint venture partners, increased costs related to surety bonds, increases in medical claims and recording a contingent provision for proposed fines from the BSEE. G&A on a per BOE basis was $4.29 Boe for 2015 compared to $4.93 per Boe for 2014. See Financial Statements and Supplementary Data – Note 10 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K for additional information.

Derivative net gain. For 2015, there was a $14.4 million derivative net gain recorded for derivative contracts for crude oil and natural gas. We entered into derivative contracts for crude oil and natural gas during the second quarter of 2015, relating to 2015 and 2016 estimated production. For 2014, the derivative net gain was $4.0 million and related to derivative contracts for crude oil. During 2014, all open positions expired and closed. For both periods, the amount includes changes in the fair value of commodity derivative contracts. See Financial Statements and Supplementary Data – Note 8 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

Interest expense. Interest expense incurred was $104.6 million in 2015, up from $86.9 million in 2014. The increase was primarily attributable to increased borrowings on the revolving bank credit facility and the issuance of the Second Lien Term Loan in May 2015 with an aggregate principal of $300.0 million and issued at a 1% discount to par. The aggregate principal amount of our Unsecured Senior Notes outstanding was $900.0 million in both periods. During 2015 and 2014, interest of $7.3 million and $8.5 million, respectively, was capitalized to unevaluated oil and natural gas properties. The decrease is primarily attributable to reclassifying certain unevaluated properties related to the Yellow Rose field to the full cost pool during the fourth quarter of 2015 and reclassifying certain unevaluated properties during the fourth quarter of 2014.

Other (income) expense, net. For 2015, $4.7 million of net expense was recorded. During 2015, the borrowing base on the revolving bank credit facility was reduced. The reductions in the borrowing base resulted in proportional reductions in the unamortized debt issuance costs of $3.2 million related to the revolving bank credit facility. In addition, a net loss on sale of assets of $1.0 million was recorded primarily related to the sale of computer equipment used for backup processes. For 2014,other income, net, was $0.2 million.

Income tax expense. Our income tax benefit for 2015 was $203.0 million compared to an income tax benefit of $4.5 million for 2014, with the change attributable primarily to increases in the pre-tax loss for 2015 compared to 2014. Our effective tax rate was 16.3% and differs from the federal statutory rate of 35% primarily due to recording a valuation allowance of $232.9 million related to federal and state deferred tax assets. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. Our effective tax rate for the year 2014 is distorted due to a small pre-tax loss; consequently, our permanent differences have a larger impact on our effective tax rate. See Financial Statements and Supplementary Data – Note 12 – Income Taxes under Part II, Item 8 in this Form 10-K for additional information.

Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings, make related interest payments and satisfy our ARO. We have funded such activities with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings.

If commodity prices were to return to the weak levels seen in the early part of 2016, especially relative to our cost of finding and producing new reserves, this could significantly affect our liquidity. In addition, other events outside of our control could significantly affect our liquidity such as demands for additional financial assurances from the BOEM or a final judgment for monetary damages in our lawsuit with Apache. If such events were to occur in the future, we may seek relief under the U.S. Bankruptcy Code, which relief may include (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of our assets and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.

Additionally, a prolonged period of weak commodity prices could have other potential negative impacts including:

During 2016, we engaged legal and financial advisors to assist the Board of Directors and our management team to evaluate the various alternatives available to us and executed the transaction described below:

Exchange Transaction. On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our Unsecured Senior Notes, due June 15, 2019 for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021 (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (the “Debt Exchange”). The reduction in the debt principal from exchanging the Unsecured Senior Notes is presented in the following table (in thousands):

The table above does not reflect accounting adjustments under ASC 470-60 (Troubled Debt Restructuring).

At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with the largest holder of our Unsecured Senior Notes. The funds from the 1.5 Lien Term Loan were used to partially pay down borrowings outstanding on the revolving bank credit facility and to pay transaction costs associated with the Exchange Transaction. We accounted for the Exchange Transaction as a Troubled Debt Restructuring under ASC 470-60. Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations from September 7, 2016 to December 31, 2016. Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt. Under ASC 470-60, interest payments related to the New Debt are reported in the financing section of the Statement of Cash Flows.

The following table presents all of our long-term debt, with December 31, 2016 being after the Exchange Transaction and June 30, 2016 and December 31, 2015 being prior to the Exchange Transaction (in thousands):

									June 30,			December 31,
	December 31, 2016								2016			2015
			PIK Payable/
			Interest Payable/			Carrying			Principal/			Principal/
	Principal		Other			Value			Other*			Other*

Revolving Bank Credit Facility, due November 2018	$	—	$	—		$	—		$	148,000		$	—

11.00% 1.5 Lien Term Loan, due November 2019		75,000		23,823			98,823			—			—

9.00 % Second Lien Term Loan, due May 2020		300,000		—			300,000			300,000			300,000

9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020		163,007		60,898			223,905			—			—

8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021		145,897		67,549			213,446			—			—

8.50% Unsecured Senior Notes, due June 2019		189,829		—			189,829			900,000			900,000
Subtotal		873,733		152,270			1,026,003			1,348,000			1,200,000

Debt premium, discount, issuance costs, net of amortization		—		(5,276	)		(5,276	)		(2,949	)		(3,145	)
Total long-term debt		873,733		146,994			1,020,727			1,345,051			1,196,855
Current maturities of long-term debt		—		8,272			8,272			—			—
Long term debt, less current maturities	$	873,733	$	138,722		$	1,012,455		$	1,345,051		$	1,196,855

A gain of $123.9 million was recognized related to the Exchange Transaction. Under ASC 470-60, a gain was recognized as the sum of (i) the future undiscounted payments (principal and interest) related to the New Debt, (ii) the fair value of the common stock issued and (iii) deal transaction costs of $18.9 million was less than the sum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan. The 60,435,544 shares of common stock issued were valued at $1.76 per share, which was the closing price on September 7, 2016.

The following table presents the calculation of the gain on exchange of debt (in thousands):

	Closing on
	September 7, 2016
(i) Future Undiscounted Payments related to New Debt:
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020:
Principal	$	159,763
PIK Payable		27,292
Interest Payable		36,850

8.50%/10.00% Third Lien PIK Toggle Notes due June 2021:
Principal		142,031
PIK Payable		30,710
Interest Payable		40,705

11.00% 1.5 Lien Term Loan, due November 2019:
Principal		75,000
Interest Payable		26,393

(ii) Fair value of common stock issued		106,366

(iii) Exchange Transaction costs		18,934

(A) Sub-Total of (i), (ii) and (iii) above			$	664,044

(iv) Carrying value of 8.50% Unsecured Senior Notes, due June 2019, exchanged:
Principal		710,171
Unamortized debt issuance costs and premium		2,796

(v) 11.00% 1.5 Lien Term Loan - funds received		75,000

(B) Sub-Total of (iv) and (v) above				787,967

Gain on exchange of debt (A less B)			$	123,923

The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility. The balance of the borrowings on the revolving bank credit facility was paid down from available cash.

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. A total of $247.7 million would become due on February 28, 2019 if acceleration were to occur.

Credit Agreement and Other Long-Term Debt. In conjunction with the Exchange Transaction, amendments were executed for the Credit Agreement. The primary items related to the recent amendments were:

Availability as of December 31, 2016 was $149.5 million. At December 31, 2016 and 2015, no amounts were outstanding and letters of credit were $0.5 million and $0.9 million, respectively, under our revolving bank credit facility. During the 2016, the outstanding borrowings on the revolving bank credit facility ranged from zero to $340.0 million.

Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. The next redetermination is scheduled to occur in April 2017. The lenders and the Company have the option for an additional redetermination every year. Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility. To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess is required to be repaid within 90 days in three equal monthly payments. Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists. The revolving bank credit facility is secured and is collateralized by substantially all of our oil and natural gas properties. The Credit Agreement terminates on November 8, 2018 and interest and fees are payable quarterly in arrears.

We currently have 20 lenders within the revolving bank credit facility, with commitments ranging from $4.1 million to $11.6 million for the current borrowing base. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively impact our liquidity position.

Conditions related to incurring additional debt, and conditions and limitations concerning early repayment of certain debt are discussed in Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K.

The Credit Agreement contains financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement and the other debt instruments as of December 31, 2016.

For our other long-term debt, the recorded amounts, maturity dates and other primary terms are described in Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K. Interest on the 1.5 Lien Term Loan is paid quarterly in arrears and is paid in cash. Interest on the Second Lien Term Loan, the Second Lien Toggle Notes, the Third Lien Toggle Notes and the Unsecured Senior Notes is paid semi-annually in arrears. For the Second Lien Term Loan, interest is paid in cash. For the Second Lien PIK Toggles Notes, we have the option of using PIK or paying in cash for the interest obligations up through March 6, 2018, then interest is paid in cash. For the Third Lien PIK Toggles Notes, we have the option of using PIK or paying in cash for the interest obligations up through September 6, 2018, then interest is paid in cash. Usage of the PIK option increases the principal amount of these notes. For the Unsecured Senior Notes, interest is paid in cash.

BOEM Matters. In the first quarter of 2016, we received several orders from the BOEM demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs. We filed various appeals to the IBLA concerning these orders. The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM demands through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to May 31, 2017.

In September 2016, we received notice from the BOEM confirming that we do not qualify to self-insure a portion of any additional financial assurance under NTL #2016-N01. In October 2016, we received from the BOEM proposal letters outlining what additional security the BOEM proposes to require for leases, ROWs and RUEs in which we are designated operator.

In December 2016, the BOEM issued to us an Order to Provide Additional Security for our 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 January 2017, BOEM, in a notice to stakeholders, extended the implementation timeline for NTL #2016-N01 by an additional six months with respect to non-sole liability leases, ROWs and RUEs, except in circumstances in which BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The extension did not affect the demand to provide financial assurance for leases, ROWs and RUEs constituting sole liability properties. The BOEM stated that the extension was needed to provide the BOEM and industry the opportunity to focus on providing additional security for sole liability properties, and to allow an opportunity for additional time and conversation concerning the non-sole liability properties.

In February 2017, the BOEM withdrew the orders it issued in December 2016 affecting so called “sole liability properties” to allow time for the new President’s 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 BOEM may 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 liabilities.

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, ordering suspension of 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. See “Risk Factors — 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, either under the current rules or new rules that may be proposed. 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” under Part I, Item 1A of this Form 10-K.

Surety Bond Collateral. Some of the sureties under our existing supplemental surety bonds have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.

The issuance of any additional surety bonds or other security to satisfy the BOEM orders, any future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and the creation of escrow accounts.

Cash flow and working capital. Net cash provided by operating activities for 2016 was $14.2 million, compared to $133.2 million for 2015. Cash flows from operating activities, before changes in working capital and ARO settlements, were $103.1 million in 2016 compared to $140.3 million in 2015. The reduction in cash flows was primarily due to lower realized prices for all our commodities - oil, NGLs and natural gas and lower production volumes, partially offset by lower operating expenses. Our combined average realized sales price per Boe decreased 12.2%, which lowered revenues $61.5 million (57.3% of the total change in revenues). Combined volumes on a Boe basis decreased 9.9%, which lowered revenues by $43.1 million. Partially offsetting were decreases in lease operating expenses of $40.4 million and lower G&A expenses of $13.4 million.

Other items affecting operating cash flows for 2016 were ARO settlements of $72.3 million and collateral deposits of $16.9 million.

Net cash used in investing activities of oil and gas properties and equipment during 2016 was $82.4 million, which represents our investments in oil and gas properties and equipment. For 2015, we had net cash provided by investing activities of $86.1 million due to the proceeds from the sale of all our onshore interest in the Yellow Rose field, partially offset by investments in oil and gas properties and equipment in the Gulf of Mexico. There were no acquisitions of significance during either period. Investments in oil and natural gas properties on an accrual basis during 2016 were $48.6 million compared to $230.2 million for 2015. In addition, adjustments from working capital changes associated with investing activities used net cash of $35.2 million in 2016 compared to net cash usage of $55.4 million for 2015. Both of these amounts represent cash expenditures in the year following the work, and accrual of the cost for accounting purposes occurred in the period the work was performed.

Net cash provided by financing activities for 2016 was $53.0 million and net cash used in financing activities for 2015 was $157.6 million. The net cash provided by financing activities for 2016 was attributable to the 1.5 Lien Term Loan, partially offset by costs related to the Exchange Transaction and interest payments related to the 1.5 Lien Term Loan. Interest related to debt meeting the definition of troubled debt restructuring under ASC 470-60, of which the 1.5 Lien Term Loan meets the definition of troubled debt restructuring, is included in net cash provided by financing activities. The net cash used in financing activities for 2015 was attributable to net repayments on the revolving bank credit facility, partially offset by the issuance of the Second Lien Term Loan.

Derivative financial instruments. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. As of December 31, 2016, we did not have any outstanding open derivatives for crude oil and natural gas.

Hurricane remediation, insurance claims and insurance coverage. During 2008, Hurricane Ike caused substantial property damage. Substantially all the costs related to Hurricane Ike have been incurred and we submitted claims under our insurance policies effective at that time, of which $171.4 million has been collected through December 31, 2016. In December 2016, we reached settlements with certain insurance companies related to claims under our excess liability policies arising from Hurricane Ike which had been made subject to adjustment or request for reimbursement by us, in which these companies agreed to pay such claims totaling $30.2 million, plus interest and attorney fees, which were received in December 2016 and January 2017. This settlement did not include claims arising from Hurricane Ike that have not yet been made subject to adjustment or requested for reimbursement by us. See Financial Statements and Supplementary Data - Note 17 – Contingencies and Note 19 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information.

We currently carry multiple layers of insurance coverage in our Energy Package covering our operating activities, with higher limits of coverage for higher valued properties and wells. The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements. We carry named windstorm coverage of $150.0 million for TLO on our Mahogany platform (Ship Shoal 349) and do not have named windstorm coverage on any other of our properties. The operational and named windstorm coverages described above are effective until June 1, 2017. Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy.

Our general and excess liability policies are effective until May 1, 2017 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility requirement under the OPA, we are required to evidence $150.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount.

Although we were able to renew our general and excess liability policies in May 2016, and our Energy Package in June 2016, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. 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 insurers will not pay our claims. However, we are not aware of any financial issues related to any of our insurance companies that would affect their ability to pay claims. We do not carry business interruption insurance.

The premiums for the above policies including brokerage fees were $8.5 million for the May/June 2016 policy renewals compared to $16.3 million for the expiring policies. The decrease in our premiums effective with the May/June 2016 renewal was primarily attributable to reductions in properties covered and the type of coverage for named windstorm damage.

Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors including the prices of crude oil, NGLs and natural gas; acquisition opportunities; liquidity and financing options; and the results of our exploration and development activities. The following table presents our capital expenditures on an accrual basis for exploration, development, acquisitions and other leasehold costs:

The following table presents our exploration and development capital expenditures on an accrual basis geographically:

During 2015, we sold our interest in the onshore Yellow Rose field. Therefore, the historical information for onshore wells was excluded from the table above.

As of December 31, 2016, we were in the process of completing one offshore development well at the Mahogany field (the A-18 well). This well was spud in 2014 and drilling was suspended in early 2015. Subsequently in August 2016, drilling was resumed and the well reached target depth during 2016. In January 2017, the A-18 well was completed and was brought on production.

See Properties –Drilling Activity under Part I, Item 2 of this Form 10-K for a breakdown of exploration and development wells and additional drilling activity information.

See Properties –Development of Proved Undeveloped Reserves under Part I, Item 2 of this Form 10-K for a discussion on activity related to proved undeveloped reserves.

We acquired the following leases from the BOEM: one lease ($0.1 million), two leases ($0.3 million) and five leases ($2.4 million) for the years 2016, 2015 and 2014, respectively.

From time to time, we sell various oil and gas properties for a variety of reasons including, change of focus, perception of value and to reduce debt, among other reasons. As previously discussed, in 2015 we sold our interest in the Yellow Rose field for $370.9 million after adjustments and reduced related ARO for $6.9 million. In 2014, there were no property sales of significance. See Financial Statements and Supplementary Data – Note 7 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information on divestitures.

Capital expenditures. Our initial capital expenditure budget for 2017 is $125 million, which excludes potential acquisitions, with over 50% allocated to development. Because of the level of commodity prices and the outlook for the remainder of 2017, we believe this level will maintain our liquidity capacity throughout 2017. We strive to maintain flexibility in our capital expenditure projects and if prices improve, we may increase our investments. See the Overview section in this Item for additional information.

Income taxes. During 2016, we made income tax payments of $0.3 million and received $7.8 million of refunds. A portion of the refund in the amount of $5.8 million related to an NOL claim for 2015 carried back to 2005 filed on Form 1139, Corporation Application for Tentative Refund. During 2015, we did not make any income tax payments nor receive any refunds of significance. For 2017, we expect that a substantial portion of our income tax will be deferred and payments, if any, will be primarily related to state taxes.

As of December 31, 2016, we have recorded current income tax receivables of $11.9 million and non-current income tax receivables of $52.1 million. The current income tax receivables relates primarily to a net operating loss claim for 2016 carried back to 2006 and is included in receivable line Joint interest, insurance reimbursement and other on the Consolidated Balance Sheet. The non-current income taxes receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to the years 2003, 2004, 2007, 2010 and 2011 filed on Form 1120X, U.S. Corporation Income Tax Return. These carryback claims are made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years. The refund claims filed on Form 1120X will require a review by the Congressional Joint Committee on Taxation and are accordingly classified as non-current.

Dividends. During 2016 and 2015, we did not pay any dividends and a suspension of dividends remains in effect. In 2014, we paid $30.3 million in dividends.

Asset retirement obligations. Each year (and often more frequently) we review and revise our ARO estimates. Our ARO at December 31, 2016 and 2015 were $334.4 million and $378.3 million, respectively. Our estimate of ARO spending in 2017 is $78.3 million. During 2016 and 2015, we revised our estimates of costs anticipated to be charged by service providers for plug and abandonment projects. As these estimates are for work to be performed in the future, and in many case, several years in the future, actual expenditures could be substantially different than our estimates. Additionally, we revise our estimates to account for the cost to comply with new and revised regulations, including increases in work scope and cost changes from interpretation of work scope. See Risk Factors – Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico under Part I, Item 1A and Financial Statements and Supplementary Data – Note 4 – Asset Retirement Obligations under Part II, Item 8 in this 10-K for additional information regarding our ARO.

Contractual obligations. At December 31, 2016, we did not have any capital leases or open derivative contracts. The following table summarizes our significant contractual obligations by maturity as of December 31, 2016:

	Payments Due by Period as of December 31, 2016
	Total		Less than One Year		One to Three Years		Three to Five Years		More Than Five Years
Long-term debt - principal ⁽¹⁾	$	924.6	$	—	$	264.8	$	659.8	$	—
Long-term debt - interest ⁽²⁾		237.3		52.1		141.4		43.8		—
Drilling rigs		4.4		4.4		—		—		—
Operating leases		10.6		1.6		3.5		3.6		1.9
Asset retirement obligations ⁽³⁾		334.4		78.3		89.4		51.1		115.6
Other liabilities and commitments ⁽⁴⁾		66.6		7.8		15.2		9.9		33.7
Total	$	1,577.9	$	144.2	$	514.3	$	768.2	$	151.2

Inflation. For 2016, our realized prices for crude oil decreased 17.1%, NGLs decreased 0.6% and natural gas decreased 5.2% from 2015. These are discussed in the Overview section above. Costs measured on a $/Boe basis (excluding DD&A and ceiling test write-downs) decreased by 8.1% in 2016 compared to 2015. The cost per Boe is impacted by factors other than cost changes, such as work activity including workovers, production levels and insurance reimbursements. Historically, costs for goods and services have moved directionally with the price of crude oil, NGLs and natural gas, as these commodities affect the demand for these goods and services. In recent years, other factors have influenced the cost of goods and services. Demand for offshore third-party contractors can be affected by hurricanes, oil spills and changes in regulations which are outside of the influences from commodity price changes. Other costs, such as insurance premiums, have fluctuated with changes in hurricane activity, the oil spills and other factors besides production volumes. Also, many commodity prices, including crude oil, copper, steel and other types of metals, have fluctuated wildly with various world events. Some of this fluctuation is due to changes in economic activity in certain parts of the world, while other changes appear to be driven by political events around the world, the changes in the value of the US dollar (both up and down) and other foreign currencies.

Seasonality. Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months. However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. As utilities continue to switch from coal to natural gas, some of this seasonality may be reduced as natural gas is used for both heating and cooling. In addition, the demand for oil is higher in the winter months, but does not fluctuate as much as natural gas. Seasonal weather changes affect our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which require us to evacuate personnel and shut in production until the storm subsides. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delaying production and sales of our oil and natural gas.

This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with GAAP in the United States. The preparation of our financial statements requires us to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our estimates on historical experience and other sources that we believe to be reasonable at the time. Changes in the facts and circumstances or the discovery of new information may result in revised estimates and actual results may vary from our estimates. Our significant accounting policies are detailed in Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.

Revenue recognition. We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. If crude oil and natural gas prices decrease, we may need to increase this liability. Also, disputes may arise as to volume measurements and allocation of production components between parties. These disputes could cause us to increase our liability for such potential exposure. We do not record receivables for those properties in which the Company has taken less than its ownership share of production which could cause us to delay recognition of amounts due us.

Full-cost accounting. We account for our investments in oil and natural gas properties using the full-cost method of accounting. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and gas properties are capitalized. Capitalization of geological and geophysical costs, certain employee costs and G&A expenses related to these activities is permitted. We amortize our investment in oil and natural gas properties, capitalized ARO and future development costs (including ARO of wells to be drilled) through DD&A, using the units-of-production method. The units-of-production method uses reserve information in its calculations. The cost of unproved properties related to acquisitions are excluded from the amortization base until it is determined that proved reserves exist or until such time that impairment has occurred. We capitalize interest on unproved properties that are excluded from the amortization base. The costs of drilling non-commercial exploratory wells are included in the amortization base immediately upon determination that such wells are non-commercial. Under the full-cost method, sales of oil and natural gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized unless an adjustment would significantly alter the relationship between capitalized costs and the value of proved reserves.

Our financial position and results of operations may have been significantly different had we used the successful-efforts method of accounting for our oil and natural gas investments. GAAP allows successful-efforts accounting as an alternative method to full-cost accounting. The primary difference between the two methods is in the treatment of exploration costs, including geological and geophysical costs, and in the resulting computation of DD&A. Under the full-cost method, which we follow, exploratory costs are capitalized, while under successful-efforts, the cost associated with unsuccessful exploration activities and all geological and geophysical costs are expensed. In following the full-cost method, we calculate DD&A based on a single pool for all of our oil and natural gas properties, while the successful-efforts method utilizes cost centers represented by individual properties, fields or reserves. Typically, the application of the full-cost method of accounting for oil and natural gas properties results in higher capitalized costs and higher DD&A rates, compared to similar companies applying the successful efforts method of accounting.

DD&A can be affected by several factors other than production. The rate computation includes estimates of reserves which requires significant judgment and is subject to change at each assessment. The determination of when proved reserves exist for our unproved properties requires judgment, which can affect our DD&A rate. Also, estimates of our ARO and estimates of future development costs require significant judgment. Actual results may be significantly different from such estimates, which would affect the timing of when these expenses would be recognized in DD&A. See Oil and natural gas reserve quantities and Asset retirement obligations below for more information.

Impairment of oil and natural gas properties. Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. Any write downs occurring as a result of the ceiling test impairment are not recoverable or reversible in future periods. We incurred significant ceiling test write-downs during 2016 and 2015. We did not have any ceiling test impairments in 2014. Ceiling test impairments in future periods are highly dependent on commodity prices, and also are impacted by other factors and events. See the Overview section for a discussion on the price sensitivity of the ceiling test under certain assumptions. For the effect of lower commodity prices on liquidity, see Risk Factors - Risks Related to Financing under Part I, Item 1A and in the Liquidity and Capital Resources section of this Item in this Form 10-K for additional information about our Credit Agreement and financing. For the effect of lower commodity prices on revenues and earnings, see Quantitative and Qualitative Disclosures on Market Risks under Part II, Item 7A in this Form 10-K for additional information.

Oil and natural gas reserve quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of DD&A and impairment assessment of our oil and natural gas properties. We make changes to DD&A rates and impairment calculations in the same period that changes to our reserve estimates are made. Our proved reserve information as of December 31, 2016 included in this Form 10-K was estimated by our independent petroleum consultant, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The accuracy of our reserve estimates is a function of:

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. See the Overview section for a discussion on the price sensitivity of the ceiling test under certain assumptions and the resulting sensitivity to reserve quantities.

Asset retirement obligations. We have significant obligations to plug and abandon all well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. Pursuant to GAAP, we are required to record a separate liability for the discounted present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet.

Inherent in the present value calculation of our liability are numerous estimates and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and changes in the legal, regulatory, environmental and political environments. Revisions to these estimates impact the value of our abandonment liability, our oil and natural gas property balance and our DD&A rates.

Fair value measurements. We measure the fair value of our derivative financial instruments by applying the income approach and using inputs that are derived principally from observable market data. Changes in the underlying commodity prices of the derivatives impact the unrealized and realized gain or loss recognized. We do not apply hedge accounting to our derivatives; therefore, the change in fair value for all outstanding derivatives, which include derivatives that are entered into in anticipation of future production, are reflected currently in our statements of operations. This can create timing differences between when the production is recognized and when the gain or loss on the derivative is recognized in the income statement. We estimate the fair value of our debt based on trades when such information is available. The market for our debt has low volumes of activity and has experienced high volatility in the past; therefore, the fair values presented may not represent the fair value of our debt in future periods.

Income taxes. We provide for income taxes in accordance with GAAP, which requires the use of the liability method of computing deferred income taxes, whereby deferred income taxes are recognized for the future tax consequences of the differences between the tax basis of assets and liabilities and the carrying amount in our financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Because our tax returns are filed after the financial statements are prepared, estimates are required in recording tax assets and liabilities. We record adjustments to reflect actual taxes paid in the period we complete our tax returns. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. The final settlement of these tax positions may occur several years after the tax return is filed and may result in significant adjustments depending on the outcome of these settlements.

Share-based compensation. We recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of the grant, which may be significantly different than on the date of vesting. We estimate forfeitures during the service period and make adjustments depending on actual experience. These adjustments can create timing differences on when expense is recognized.

Troubled Debt Restructuring. We accounted for the Exchange Transaction as a troubled debt restructuring pursuant to the guidance under ASC 470-60. Under ASC 470-60, the carrying value of the New Debt is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016. Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt. The amounts recorded for the carrying value of the New Debt were determined using certain assumptions, which primarily were: (i) the PIK options, when available, would be fully utilized and (ii) the maturity of 1.5 Lien Term Loan and the Third Lien PIK Toggle Notes would not be accelerated, which implies the Unsecured Senior Notes will be refinanced prior to February 28, 2019. These assumptions may prove to be incorrect, which would change the carrying value of the New Debt.

We are exposed to market risks arising from fluctuating prices of crude oil, NGLs, natural gas and interest rates as discussed below. We have utilized derivative contracts to reduce the risk of fluctuations in commodity prices and expect to use these instruments in the future. We entered into derivative contracts for crude oil and natural gas during 2015 and had no open derivative contracts as of December 31, 2016. We do not designate our commodity derivative contracts as hedging instruments. While previous derivative contracts were intended to reduce the effects of volatile oil prices, they may also have limited income from favorable price movements. For additional details about our derivative contracts, refer to Financial Statements and Supplementary Data – Note 6 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K.

Commodity price risk. Our revenues, profitability and future rate of growth substantially depend upon market prices for crude oil, NGLs and natural gas, which fluctuate widely. Crude oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. For example, assuming a 10% decline in our average realized oil, NGLs and natural gas sales prices in 2016 and assuming no other items had changed, our loss before income tax would have increased by approximately $40 million in 2016. If costs and expenses of operating our properties had increased by 10% in 2016, our loss before income tax would have increased by approximately $18 million in 2016. These estimates exclude the potential increase to the ceiling test write-down resulting in further net losses, as a full reserve and PV-10 analysis would be required for such pro forma calculations. The amounts above would be representative of the effect on operating cash flows under the price and cost change assumptions.

Interest rate risk. As of December 31, 2016, we had no borrowings outstanding on our revolving bank credit facility and during 2016 we had amounts outstanding that ranged from zero to $340.0 million. The revolving bank credit facility has a variable interest rate which is primarily impacted by the rates for the London Interbank Offered Rate and the current margin ranges from 3.00% to 4.00% depending on the amount outstanding. In 2016, if interest rates would have been 100 basis points higher (an additional 1%); our interest expense would have been approximately $1.3 million higher. We did not have any derivative contracts related to interest rates as of December 31, 2016.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States (GAAP). Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework).

Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2016 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

We have audited W&T Offshore, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). W&T Offshore, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, W&T Offshore, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of W&T Offshore, Inc. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in shareholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2016 and our report dated March 2, 2017 expressed an unqualified opinion thereon.

We have audited the accompanying consolidated balance sheets of W&T Offshore, Inc. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in shareholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of W&T Offshore, Inc. and subsidiaries at December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), W&T Offshore, Inc.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 2, 2017 expressed an unqualified opinion thereon.

	December 31,
	2016			2015
Assets
Current assets:
Cash and cash equivalents	$	70,236		$	85,414
Receivables:
Oil and natural gas sales		43,073			35,005
Joint interest		21,885			22,000
Insurance reimbusrements		30,100			12
Income tax		11,943			—
Total receivables		107,001			57,017
Prepaid expenses and other assets		14,504			26,879
Total current assets		191,741			169,310
Property and equipment - at cost:
Oil and natural gas properties and equipment (full cost method, of which $0 at December 31, 2016 and $18,595 at December 31, 2015 were excluded from amortization)		7,932,504			7,902,494
Furniture, fixtures and other		20,898			20,802
Total property and equipment		7,953,402			7,923,296
Less accumulated depreciation, depletion and amortization		7,406,349			6,933,247
Net property and equipment		547,053			990,049
Deferred income taxes		—			27,595
Restricted deposits for asset retirement obligations		27,371			15,606
Income tax receivables		52,097			—
Other assets		11,464			5,462
Total assets	$	829,726		$	1,208,022
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	81,039		$	109,797
Undistributed oil and natural gas proceeds		26,254			21,439
Asset retirement obligations		78,264			84,335
Long-term debt		8,272			—
Accrued liabilities		9,200			11,922
Total current liabilities		203,029			227,493
Long-term debt, less current portion		1,012,455			1,196,855
Asset retirement obligations, less current portion		256,174			293,987
Other liabilities		17,105			16,178
Commitments and contingencies (Notes 15 and 17)
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at December 31, 2016 and 2015		—			—
Common stock, $0.00001 par value; 200,000,000 shares authorized; 140,543,545 issued and 137,674,372 outstanding at December 31, 2016; 79,375,662 issued and 76,506,489 outstanding at December 31, 2015		1			1
Additional paid-in capital		539,973			423,499
Retained earnings (deficit)		(1,174,844	)		(925,824	)
Treasury stock, at cost; 2,869,173 shares at December 31, 2016 and 2015		(24,167	)		(24,167	)
Total shareholders’ deficit		(659,037	)		(526,491	)
Total liabilities and shareholders’ deficit	$	829,726		$	1,208,022

	Year Ended December 31,
	2016			2015			2014

Revenues	$	399,986		$	507,265		$	948,708
Operating costs and expenses:
Lease operating expenses		152,399			192,765			264,751
Production taxes		1,889			3,002			7,932
Gathering and transportation		22,928			17,157			19,821
Depreciation, depletion and amortization		194,038			373,368			490,469
Asset retirement obligations accretion		17,571			20,703			20,633
Ceiling test write-down of oil and natural gas properties		279,063			987,238			—
General and administrative expenses		59,740			73,110			86,999
Derivative (gain) loss		2,926			(14,375	)		(3,965	)
Total costs and expenses		730,554			1,652,968			886,640
Operating income (loss)		(330,568	)		(1,145,703	)		62,068
Interest expense:
Incurred		92,791			104,592			86,922
Capitalized		(520	)		(7,256	)		(8,526	)
Gain on exchange of debt		123,923			—			—
Other (income) expense, net		(6,520	)		4,663			(208	)
Loss before income tax benefit		(292,396	)		(1,247,702	)		(16,120	)
Income tax benefit		(43,376	)		(202,984	)		(4,459	)
Net loss	$	(249,020	)	$	(1,044,718	)	$	(11,661	)
Basic and diluted loss per common share	$	(2.60	)	$	(13.76	)	$	(0.16	)

	Common Stock				Additional			Retained								Total
	Outstanding				Paid-In			Earnings			Treasury Stock					Shareholders’
	Shares		Value		Capital			(Deficit)			Shares		Value			Equity (Deficit)

Balances at December 31, 2013		75,592	$	1	$	403,564		$	161,212			2,869	$	(24,167	)	$	540,610
Cash dividends		—		—		—			(30,260	)		—		—			(30,260	)
Share-based compensation		—		—		14,744			—			—		—			14,744
Stock issued		307		—		—			—			—		—			—
RSUs and shares surrendered for payroll taxes		—		—		(848	)		—			—		—			(848	)
Other		—		—		(2,880	)		(397	)		—		—			(3,277	)
Net loss		—		—		—			(11,661	)		—		—			(11,661	)
Balances at December 31, 2014		75,899		1		414,580			118,894			2,869		(24,167	)		509,308
Share-based compensation		—		—		10,242			—			—		—			10,242
Stock issued		607		—		—			—			—		—			—
RSUs and shares surrendered for payroll taxes		—		—		(674	)		—			—		—			(674	)
Other		—		—		(649	)		—			—		—			(649	)
Net loss		—		—		—			(1,044,718	)		—		—			(1,044,718	)
Balances at December 31, 2015		76,506		1		423,499			(925,824	)		2,869		(24,167	)		(526,491	)
Share-based compensation		—		—		11,013			—			—		—			11,013
Stock issued		61,168		—		106,366			—			—		—			106,366
RSUs surrendered for payroll taxes		—		—		(905	)		—			—		—			(905	)
Net loss		—		—		—			(249,020	)		—		—			(249,020	)
Balances at December 31, 2016		137,674	$	1	$	539,973		$	(1,174,844	)		2,869	$	(24,167	)	$	(659,037	)

	Year Ended December 31,
	2016			2015			2014

Operating activities:
Net loss	$	(249,020	)	$	(1,044,718	)	$	(11,661	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		211,609			394,071			511,102
Ceiling test write-down of oil and gas properties		279,063			987,238			—
Gain on exchange of debt		(123,923	)		—			—
Debt issuance costs write-down/amortization of debt items		2,548			4,411			701
Share-based compensation		11,013			10,242			14,744
Derivative (gain) loss		2,926			(14,375	)		(3,965	)
Cash receipts (payments) on derivative settlements, net		4,746			6,703			(5,318	)
Deferred income taxes		28,392			(203,272	)		(4,760	)
Changes in operating assets and liabilities:
Oil and natural gas receivables		(7,005	)		32,236			29,510
Joint interest receivables and insurance		(1,126	)		21,633			(4,255	)
Income taxes		(64,274	)		(7	)		3,143
Prepaid expenses and other assets		(14,946	)		17,816			15,012
Asset retirement obligation settlements		(72,320	)		(32,555	)		(74,313	)
Accounts payable, accrued liabilities and other		6,497			(46,195	)		4,881
Net cash provided by operating activities		14,180			133,228			474,821
Investing activities:
Acquisition of property interest in oil and natural gas properties		—			—			(72,234	)
Investment in oil and natural gas properties and equipment		(48,606	)		(230,161	)		(554,378	)
Changes in operating assets and liabilities associated with investing activities		(35,194	)		(55,425	)		37,450
Net proceeds from sales of assets		1,500			372,939			—
Purchases of furniture, fixtures and other		(96	)		(1,278	)		(3,340	)
Net cash provided by (used in) investing activities		(82,396	)		86,075			(592,502	)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility		340,000			263,000			556,000
Repayments of long-term debt - revolving bank credit facility		(340,000	)		(710,000	)		(399,000	)
Issuance of 1.5 Lien Term Loan		75,000			—			—
Issuance of Second Lien Term Loan		—			297,000			—
Payment of interest on 1.5 Lien Term Loan		(2,570	)		—			—
Debt exchange/issuance costs		(18,464	)		(6,669	)		—
Dividends to shareholders		—			—			(30,260	)
Other		(928	)		(886	)		(1,193	)
Net cash provided by (used in) financing activities		53,038			(157,555	)		125,547
Increase (decrease) in cash and cash equivalents		(15,178	)		61,748			7,866
Cash and cash equivalents, beginning of period		85,414			23,666			15,800
Cash and cash equivalents, end of period	$	70,236		$	85,414		$	23,666

W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”, is an independent oil and natural gas producer focused primarily in the Gulf of Mexico. On October 15, 2015, a substantial amount of our interest in onshore acreage was sold, which is described in Note 7. We are active in the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).

Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

Accounting Standards Update No. 2016-09 (“ASU 2016-09”), Compensation – Stock Compensation (Subtopic 718) was early adopted as of December 31, 2016. The amendment’s objective is simplification of several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Consolidated Statements of Cash Flows. The early adoption affected the statements of cash flows as to the classification of cash paid for employee income taxes and payroll taxes, which were funded through the forfeiture of vested restricted stock units (“RSUs”). Previously, these cash payments were classified as operating activities. The updated standard requires such cash transactions be classified as financing activities. The reclassification was applied retrospectively on the statements of cash flows for the years 2014 and 2015 and resulted in reclassification of $0.8 million and $0.7 million, respectively. None of the other amendments under ASU 2016-09 had an effect on our financial statements and the early adoption of ASU 2016-09 did not affect the Consolidated Balance Sheets, Consolidated Statements of Operations or the Consolidated Statements of Changes in Shareholders’ Equity (Deficit).

The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital and future rate of growth. The prices of these commodities began falling in the second half of 2014, were significantly lower during 2015 and lower still in 2016 compared to prior years.

We took a number of steps during 2015 and 2016 to mitigate the effects of these lower prices including: (i) significantly reducing capital spending from previous year levels and budgeting conservative capital spending for 2017 (exclusive of acquisitions); (ii) restructuring our debt and issuing our common stock through an exchange transaction, which is described in Note 2, (iii) receiving funds through two debt issuances, which are described in Note 2 (iv) suspending our quarterly common stock dividend; (iv) implementing numerous cost reduction projects to reduce our operating costs; and (v) selling our interest in the Yellow Rose onshore field, which is described in Note 7.

During 2016, the Bureau of Ocean Energy Management (“BOEM”) issued orders to us concerning financial assurances related to plug and abandonment (decommissioning) obligations for Federal offshore leases, including an order issued to us in December 2016 regarding additional security required for sole liability properties. In July 2016, effective September 2016, the BOEM issued Notice to Lessees #2016-N01 (“NTL #2016-N01”), related to obligations for decommissioning activities on the Outer Continental Shelf (“OCS”) for leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”). In January 2017, the BOEM extended the implementation timeline by an additional six months of NTL #2016-N01 as to leases, ROWs and RUEs for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions. In February 2017, the BOEM withdrew the sole liability orders it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program. See Note 17 and 19 for additional information.

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations for at least 12 months from the date of issuance of this Form 10-K, which is the threshold of a going concern under GAAP; however, we cannot predict with any certainty future commodity prices or the actions of the BOEM concerning financial assurance requirements, either of which could affect our operations and liquidity levels.

We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents.

We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which we have taken less than our ownership share of production. At December 31, 2016 and 2015, $5.3 million and $6.9 million, respectively, were included in current liabilities related to natural gas imbalances.

Our customers are primarily large integrated oil and natural gas companies and large financial institutions. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary. We historically have not had any significant problems collecting our receivables, but with the decline in commodity prices, several oil and gas companies have filed for bankruptcy, including some of our joint interest partners. We use the specific identification method of determining if an allowance for doubtful accounts is needed. As of December 31, 2016 and 2015, $7.6 million and $2.5 million, respectively, were recorded as an allowance for doubtful accounts. During 2016 and 2015, there were no reductions recorded in the allowance for doubtful accounts (no collections of accounts previously reserved and no permanent write-off of receivable accounts).

The following identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas.

We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing.

We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance company’s adjuster reviews and approves such costs for payment or when the insurance company has agreed to reimbursement amounts. Claims that have been processed in this manner have customarily been paid on a timely basis. See Note 5, 17 and 19 for information related to settlement of previously unpaid claims by certain insurance companies.

Amounts recorded in Prepaid expenses and other on the Consolidated Balance Sheets are expected to be realized within one year. Items representing 5% or more of total current assets in either period presented are disclosed in the following table:

We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred.

Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as we have made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial.

We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and equipment on the Consolidated Balance Sheets.

Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.

Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.

Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.

Due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas, we recorded ceiling test write-downs in 2015 and 2016, which are reported as a separate line in the Statements of Operations. The average price using the SEC required methodology at December 31, 2016 was $39.25 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.48 per million British Thermal Unit (“MMBtu”) for Henry Hub natural gas. These prices are before adjustments for quality, transportation, fees, energy content and regional price differentials. The ceiling test write-downs of the carrying value of our oil and natural gas properties were $279.1 million and $987.2 million for 2016 and 2015, respectively. There was no ceiling test write-down in the fourth quarter of 2016. We did not record a ceiling test write-down during 2014. If average crude oil and natural gas prices decrease from 2016 levels, it is possible that a ceiling test write-down will be recorded during 2017.

We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. For additional information, refer to Note 4.

We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 21 for additional information about our proved reserves.

Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility. As of December 31, 2016, we did not have any open derivative financial instruments. We do not enter into derivative instruments for speculative trading purposes.

Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. Whenever we have entered into derivative contracts, we did not designate our commodity derivatives as hedging instruments, therefore, all changes in fair value are recognized in earnings.

We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. We believe the carrying amount of debt under our 11.00% 1.5 Lien Term Loan, due November 2019, (the “1.5 Lien Term Loan”) approximates fair value because the debt was recently executed and reflective of market rates and conditions.

Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs are: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves, and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates. The estimates and assumptions are determined by management and third-parties. The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values can vary significantly from estimates that are made.

We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Accounting Standard Codification. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. See Note 12 for additional information.

We accounted for an exchange transaction, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”). Under ASC 470-60, the carrying value of the newly issued debt, as described in Note 2, is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the newly issued debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016. Additionally, no interest expense related to the newly issued debt will be recorded in future periods as payments of interest on the newly issued debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the newly issued debt. See Note 2 for additional information.

Debt issuance costs associated with our revolving bank credit facility are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. Unamortized debt issuance costs associated with our revolving bank credit facility is reported within Other Assets (noncurrent) and unamortized debt issuance costs associated with our other debt is reported as a reduction in Long-Term Debt, less current maturities in the Consolidated Balance Sheets. See Note 2 for additional information.

Premiums and discounts are recorded in Long-Term Debt, less current maturities in the Consolidated Balance Sheets and are amortized over the term of the related debt using the effective interest method.

Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 10 for additional information.

Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of loss per share under the two-class method when the effect is dilutive. For additional information, refer to Note 13.

For 2016, the amount includes $7.7 million of income related to the settlement of certain insurance claims. In 2016 and 2015, the amount includes write-offs of debt issuance costs of $1.4 million and $3.2 million, respectively, related to a reduction in the borrowing base of the revolving bank credit facility under the Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”). The write-offs of debt issuance costs in both 2016 and 2015 are included as an adjustment to net income in determining Net cash provided by operating activities in the Consolidated Statements of Cash Flows as the write-offs were non-cash transactions.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606). ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance. The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017. Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application. Our current intention is to adopt the standard utilizing the modified retrospective approach. Our evaluation to date is the adoption of ASU 2014-09 is not expected to have a material impact on our consolidated financial statements. We have not fully completed our analysis and subsequent guidance may change this assessment. Our disclosures related to revenue will be modified when the new guidance is effective. ASU 2014-09 will be effective for us in the first quarter of 2018.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842). Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. However, unlike current GAAP, which requires only capital leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet. ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements. ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources. Our current operating leases that will be impacted by ASU 2016-02 when it is effective are leases for office space in Houston and New Orleans, although ASU 2016-02 may impact the accounting for leases related to operations equipment depending on the term of the lease. We currently do not have any leases classified as financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach. We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326). The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018. We have not yet fully determined or quantified the effect ASU 2016-13 will have on our financial statements.

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 addresses the classification of several items that previously had diversity in practice. Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims. The item described in clause (b) would be the only such item changed under our historical classification in the Statement of Cash Flows (financing vs. investing) and the amount of such change would not be material; therefore, we do not anticipate the new standard will have a material effect on our Statement of Cash Flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash. ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is expected to change some of the presentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period.

As of December 31, 2016 and 2015, our long-term debt was as follows (in thousands):

									December 31,
	December 31, 2016								2015
			PIK Payable/
			Interest Payable/			Carrying			Principal/
	Principal		Other			Value			Other*
11.00% 1.5 Lien Term Loan, due November 2019	$	75,000	$	23,823		$	98,823		$	—

9.00 % Second Lien Term Loan, due May 2020		300,000		—			300,000			300,000

9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020		163,007		60,898			223,905			—

8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021		145,897		67,549			213,446			—

8.50% Unsecured Senior Notes, due June 2019		189,829		—			189,829			900,000
Subtotal		873,733		152,270			1,026,003			1,200,000

Debt premium, discount, issuance costs, net of amortization		—		(5,276	)		(5,276	)		(3,145	)
Total long-term debt		873,733		146,994			1,020,727			1,196,855
Current maturities of long-term debt		—		8,272			8,272			—
Long term debt, less current maturities	$	873,733	$	138,722		$	1,012,455		$	1,196,855

Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2016 are as follows (in millions): 2017–$8.2; 2018–$23.8; 2019–$303.7; 2020–$510.1; thereafter–$180.1. See below for discussion on the determination of recorded amounts.

On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our 8.500% Senior Notes (the “Unsecured Senior Notes”), due June 15, 2019, for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”). At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with the then largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”). We accounted for the Exchange Transaction as a Troubled Debt Restructuring pursuant to the guidance under ASC 470-60. Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016. Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.

A gain of $123.9 million was recognized related to the Exchange Transaction. Under ASC 470-60, a gain was recognized as the sum of (i) the future undiscounted payments (principal and interest) related to the New Debt, (ii) the fair value of the common stock issued and (iii) deal transaction costs of $18.9 million was less than the sum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan. The shares of common stock issued were valued at $1.76 per share, which was the closing price on September 7, 2016. The effect on basic and diluted earnings per share for 2016 was a $1.30 per share, which assumes the gain would not affect income tax benefit for 2016.

In conjunction with the Exchange Transactions, certain terms of our Credit Agreement were modified and are reflected in the description of the Credit Agreement below.

The Credit Agreement provides a revolving bank credit facility. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders (historically in the spring and fall), and we and our lenders may each request one additional determination per year. The borrowing base as of December 31, 2016 was $150.0 million. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility. 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. Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists. The revolving bank credit facility is secured and is collateralized by our oil and natural gas properties. The Credit Agreement terminates on November 8, 2018.

The Credit Agreement contains covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock or outstanding debt; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts or enter into certain hedging contacts in excess of 75% of projected oil and gas production on a monthly basis; (vii) enter into certain liens; and (viii) enter into certain other transactions, without the prior consent of the lenders. We are permitted to issue additional indebtedness if certain conditions are met including: (i) the additional debt is subordinate in security and right of payment; (ii) the borrowers enter into an intercreditor agreement with terms acceptable to the Administrative Agent of the Credit Agreement; (iii) we are in compliance with the financial covenants after giving pro forma effect to the additional indebtedness; and (iv) such additional unsecured indebtedness matures at least six months after the maturity date of the Credit Agreement and is not subject to restrictive covenants materially more onerous than those provided for in the Credit Agreement. With consent of the lenders, such limitation will not apply to the repurchase of our existing debt in an aggregate principal amount equal to or less than the aggregate principal amount of any new issuance of such debt. We are permitted to redeem, repurchase, prepay or defease up to $35 million of our Unsecured Senior Notes if after giving effect to such redemption, repayment, prepayment or defeasance: (i) no amounts are outstanding on the revolving bank credit facility; (ii) letters of credit outstanding do not exceed $5 million; (iii) the Consolidated Cash balance is at least $35 million after the redemption or repayment; and (iv) no event of default shall have occurred and be continuing, and no borrowing base deficiency shall have occurred and be continuing or result therefrom.

The Credit Agreement also contains various customary covenants for certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, and for customary events of default. These financial test ratios and limits as of December 31, 2016 and thereafter are: (i) the First Lien Leverage Ratio must be less than 2.50 to 1.00 through June 30, 2017, then 2.00 to 1.00 thereafter; (ii) the Asset Coverage Ratio must be not less than 1.25 to 1.00 as of December 31, 2016, then is suspended thereafter; and (ii) the Current Ratio must be greater than 1.00 to 1.00. As of December 31, 2016, the current ratio was 2.93 to 1.00. As of December 31, 2016, the First Lien Leverage Ratio and the Asset Coverage Ratio were in compliance, but not meaningful as no borrowings were outstanding on the revolving bank credit facility and only minor amounts of letters of credit were outstanding. The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control. The Credit Agreement contains cross-default clauses with the other debt agreements, and these agreements contain similar cross-default clauses with the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2016.

We are required to have deposit accounts only with banks party to the Credit Agreement with certain exceptions. We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are greater than $5 million.

Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 3.00% to 4.00% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.50%, or (c) LIBOR plus 1.0%, plus applicable margin ranging from 2.00% to 3.00%. The unused portion of the borrowing base is subject to a commitment fee of 0.50%. The estimated annual effective interest rate was 3.3% for 2016 for borrowings under the Credit Agreement. The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs.

During 2016 and 2015, the borrowing base under the Credit Agreement was reduced. The reductions in the borrowing base resulted in proportional reductions in the unamortized costs related to the Credit Agreement of $1.4 million and $3.2 million in 2016 and 2015, respectively, which is included in the line Other (income)/expense, net on the Consolidated Statements of Operations.

At December 31, 2016 and 2015, we had no borrowings outstanding under the revolving bank credit facility. At December 31, 2016 and 2015, we had $0.5 million and $0.9 million, respectively, outstanding in letters of credit under the revolving bank credit facility.

As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019. The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Interest accrues at 11.00% per annum and is payable quarterly in cash. The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction. The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement. The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes. All future undiscounted cash flows have been included in the carrying value under ASC 470-60. Current maturities of our long-term debt represent the cash interest payable for the 1.5 Lien Term Loan payable in the next 12 months. The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; and (vii) enter into transactions with affiliates. We were in compliance with those covenants as of December 31, 2016.

In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%, was issued at a 1.0% discount to par and matures on May 15, 2020 and is recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs. Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15. The estimated annual effective interest rate on the Second Lien Term Loan is 9.7%, which includes amortization of debt issuance costs and discounts. The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. The Second Lien Term Loan is effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien PIK Toggle Notes (discussed below). We are subject to various covenants under the terms governing the Second Lien Term Loan including, without limitation, covenants that limit our ability to incur other debt, pay dividends or distributions on our equity, merge or consolidate with other entities and make certain investments in other entities. We were in compliance with those covenants as of December 31, 2016.

As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016, with a maturity date of May 15, 2020. Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year. The Second Lien PIK Toggle Notes contain payment-in-kind (“PIK”) interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period. We have the option for the first 18 months to pay all or a portion of interest in kind at a rate of 10.75% per annum, except that the initial interest payment on November 15, 2016 had to be paid solely using PIK. The Second Lien PIK Toggle Notes are secured by a second-priority lien on all of our assets that are pledged under the Credit Agreement. The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien Term Loan. For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount. This assumption for PIK utilization was also used in calculating the maturity amounts disclosed above. All future undiscounted cash flows have been included in the carrying value under ASC 470-60. The Second Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. We were in compliance with those covenants as of December 31, 2016.

As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016, with a maturity date of June 15, 2021. The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year. The Third Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period. We have the option for the first 24 months to pay all or a portion of interest in kind at a rate of 10.00% per annum, except that the initial interest payment on December 15, 2016 had to be paid solely using PIK. The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement. The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes. For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount. All future undiscounted cash flows have been included in the carrying value under ASC 470-60. The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. We were in compliance with those covenants as of December 31, 2016.

At December 31, 2016 and 2015, our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019, were classified as long-term at their carrying value. Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15. The estimated annual effective interest rate on the Unsecured Senior Notes is 8.4%, which includes amortization of debt issuance costs and premiums. We and our restricted subsidiaries are subject to certain covenants under the indenture governing the Unsecured Senior Notes, which limit our and our restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries. We were in compliance with those covenants as of December 31, 2016.

For information about fair value measurements of our long-term debt, refer to Note 3.

Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk.

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

The following table presents the fair value of our long-term debt (in thousands):

The fair value of long-term debt is based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2. An exception is the fair value of the 1.5 Lien Term Loan, which is held by one entity, and was not traded since its inception in September 2016. As the 1.5 Lien Term Loan was recently executed, the fair value was assumed to be the carrying value, excluding amounts recorded for future interest payments.

As of December 31, 2016, there were no open derivatives financial instruments. As of December 31, 2015, the carrying value of our open derivative financial instruments equaled the estimated fair value. We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices.

The carrying value of our long-term debt is disclosed in Note 2 above. For additional information about our derivative financial instruments, refer to Note 8.

Asset retirement obligations associated with the retirement of tangible long-lived assets are required to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our credit-adjusted risk-free rate when the liability is initially recorded. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

During 2016, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2016, partially offset by increases from accretion and revisions of previous estimates. Upward revisions were primarily related to sustained casing pressure issues for idle iron at our West Cameron fields identified while performing preliminary plug and abandonment work at these fields. In addition, increases were attributable to non-operated properties. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations.

During 2015, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2015, partially offset by increases from accretion. Revisions were basically flat as some service providers reduced their costs of goods and services, some service provider costs remained flat and some service provider costs estimates were increased, all of which were incorporated into our estimates. In addition, revisions were made for scope changes and on the estimates of timing of when the work will be performed. Liability increases from acquisitions and wells drilled were basically offset by reductions from dispositions.

During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

For 2016, 2015 and 2014, we received insurance reimbursements of $10.2 million, $0.2 million and $12.2 million, respectively, primarily related to hurricane damage. In addition, we recorded receivables of $30.1 million as of December 31, 2016 for recent settlements with certain insurance companies related to Hurricane Ike claims within Receivables – Joint interest, insurance reimbursements and other on the Consolidated Balance Sheets. Cash receipts from insurance proceeds are included within Net cash provided by operating activities in the Consolidated Statements of Cash Flows and are primarily recorded as reductions in Oil and natural gas properties and equipment on the Consolidated Balance Sheets, with some amounts recorded as reductions in Lease operating expense, General and administrative expenses and Other income (expense), net in the Consolidated Statements of Operations. From the third quarter of 2008 through December 31, 2016, we have received $171.4 million cumulative reimbursements from insurance companies related to hurricane reimbursements.

Restricted deposits as of December 31, 2016 and 2015 consisted of funds escrowed for collateral related to the future plugging and abandonment obligations of certain oil and natural gas properties.

Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through surety bonds or payments to an escrow account or a combination thereof. Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met. See Note 15 for potential future security requirements.

On October 15, 2015, we sold certain onshore oil and natural gas property interests to Ajax Resources, LLC (“Ajax”) for approximately $370.9 million in cash, which includes certain customary price adjustments, and Ajax assumed responsibility for the related ARO. The effective date of the sale was January 1, 2015. A net purchase price adjustment of $0.9 million for final customary effective date adjustments was recorded during 2016. Ajax acquired all of our interest in the Yellow Rose field in the Permian Basin, covering approximately 25,800 net acres in Andrews, Martin, Gaines and Dawson counties in West Texas. We retained 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. We used a portion of the proceeds of the sale to repay all outstanding borrowings under the revolving bank credit facility, while the remaining balance of approximately $100.0 million was added to available cash.

Under the full-cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center. The sale to Ajax did not represent greater than 25% of our proved reserves of oil and natural gas attributable to the full cost pool. As a result, alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool was not deemed significant and no gain or loss was recognized from the sale.

On September 15, 2014, the Parent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the Mobile Bay blocks 113 and 132 (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively, “Fairway”). The Fairway Field is located in the state waters of Alabama and the Yellowhammer gas processing plant is located in the state of Alabama. The effective date of the transaction was July 1, 2014. The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO. A net purchase price increase of $1.3 million for customary final closing adjustments was recorded in 2015. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

The following table presents the purchase price allocation, including estimated adjustments, for the increased ownership interest in Fairway (in thousands):

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the acquisition of this additional working interest in Fairway.

On May 20, 2014, Energy VI entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Woodside Energy (USA) Inc. (“Woodside”). The properties acquired from Woodside (the “Woodside Properties”) consisted 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. All of the Woodside Properties are located in the Gulf of Mexico. The effective date of the transaction was November 1, 2013. The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO. A net purchase price increase of $0.2 million for customary final closing adjustments was recorded in 2015. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Woodside Properties (in thousands):

2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information - Unaudited

The increase in working interest ownership for Fairway was not included in our consolidated results until the property transfer date, which occurred in September 2014 and the incremental revenue and operating expenses were immaterial for 2014. Unaudited pro forma information is not presented as the pro forma information is not materially different from the reported results for 2014 and 2013.

The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred on May 20 2014. For 2015, the Woodside Properties accounted for $24.4 million of revenues, $9.5 million of direct operating expenses, $14.4 million of depreciation, depletion, amortization and accretion (“DD&A”) and no income tax expense, resulting in $0.5 million of net income. For the period of May 20, 2014 to December 31, 2014, the Woodside Properties accounted for $28.4 million of revenues, $5.5 million of direct operating expenses, $11.0 million of DD&A and $4.2 million of income taxes, resulting in $7.7 million of net income. The net income attributable to the Woodside Properties does not reflect certain expenses, such as general and administrative expenses (“G&A”) and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Woodside Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.

In accordance with the applicable accounting guidance, the unaudited pro forma financial information was computed as if the acquisition of the Woodside Properties had been completed on January 1, 2013. The financial information was derived from W&T’s audited historical consolidated financial statements for annual periods, W&T’s unaudited historical condensed consolidated financial statements for interim periods, and the Woodside Properties’ unaudited historical financial statements for the annual and interim periods.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Woodside Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2013. Had we owned the Woodside Properties during the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Woodside; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Woodside Properties may have been different.

The following table presents a summary of our pro forma financial information (in thousands, except earnings per share):

For the pro forma financial information, certain information was derived from our financial records, Woodside’s financial records and certain information was estimated.

The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands):

The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas. All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations. Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, and we do not require collateral from our derivative counterparties.

Each derivative contract is recorded on the balance sheet as an asset or liability at fair value as of the respective period. We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts were recognized currently in earnings during the periods presented. The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities on the Consolidated Statements of Cash Flows. While these contracts are intended to reduce the effects of price volatility, they may have limited incremental income from favorable price movements.

As of December 31, 2016, we did not have any open derivative contracts. During 2015, we entered into crude oil and natural gas derivative contracts for a portion of our anticipated future production. Some of the commodity derivative contracts are known as “three-way collars” consisting of a purchased put option, a sold call option and a purchased call option, each at varying strike prices. The strike prices of the contracts were set so that the contracts were premium neutral (“costless”), which means no net premium was paid to or received from a counterparty. The three-way collar contracts are structured to provide price risk protection if the commodity price falls below the strike price of the put option and provides us the opportunity to benefit if the commodity price rises above the strike price of the purchased call option. In addition, we entered into oil derivative contracts known as “two-way”, “costless” collars, which consist of a purchased put option and a sold call option. These two-way collars provide price risk protection if crude oil prices fall below certain levels, but have the potential to limit incremental income from favorable price movements above certain limits. The oil contracts are based on WTI crude oil prices as quoted off the NYMEX. The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX. During 2014, we used crude oil swap contracts and have used various derivative instruments in prior years to manage our exposure to commodity price risk from sales of our oil and natural gas.

The following balance sheet line items included amounts related to the estimated fair value of our open commodity derivative contracts as reported in the following table (in thousands):

Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands):

Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows and were as follows (in thousands):

During 2016 and 2015, all our commodity derivative contracts permit netting of derivative gains and losses upon settlement. In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity. If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments. If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts. Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability. For the open derivative contracts as of December 31, 2015, there would have been no difference if the contracts were presented on net basis.

During 2016, after receiving shareholder approval, the Company increased the amount of common stock authorized from 118.3 million shares to 200.0 million shares, which allowed for the issuance of 60.4 million additional shares in conjunction with the Exchange Transaction.

During 2016 and 2015, we did not pay any dividends and dividends are currently suspended. During 2014, we paid regular cash dividends of $0.40 per common share.

In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders and amendments to the Plan were approved by our shareholders in 2016. The Plan covers the Company’s eligible employees and consultants. In addition to other cash and share-based compensation awards, the Plan is designed to grant awards that qualify as performance-based compensation within the meaning of section 162(m) of the IRC. The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants the President and the Chief Executive Officer (“CEO”) with authority over the administration of awards granted to participants that are not subject to section 16 of the Exchange Act (as applicable, the “Committee”).

Pursuant to the terms of the Plan, the Committee establishes the performance criteria and may use a single measure or combination of business measures as described in the Plan. Also, individual goals may be established by the Committee. Performance awards may be granted in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, or other awards related to stock, and awards may be paid in cash, stock, or any combination of cash and stock, as determined by the Committee. The performance awards granted under the Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of performance award) will generally be paid within 90 days following the applicable year end.

On May 4, 2016, after receiving shareholder approval, 3,300,000 shares of common stock were added to the amount available for issuance under the Plan. As of December 31, 2016, there were 6,933,337 shares of common stock available for issuance in satisfaction of awards under the Plan. RSUs reduce the shares available in the Plan when settled in shares of common stock, net of withholding tax.

For 2016, 2015 and 2014, performance awards under the Plan were granted in the form of RSUs. As defined by the Plan, RSUs are rights to receive stock, cash or a combination thereof at the end of a specified vesting period, subject to certain terms and conditions as determined by the Committee. RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period using a predefined scale based on the Company achieving certain predetermined performance criteria. Vesting occurs upon completion of the specified vesting period applicable to each grant. Subsequent to the determination of the performance achievement and prior to vesting, the RSUs earn dividend equivalents at the same rate as dividends paid on our common stock. RSUs are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period.

During 2016, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 2016 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2016. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2016, the Company was below target for Adjusted EBITDA and achieved target for Adjusted EBITDA Margin.

During 2015, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2015 and (ii) Adjusted EBITDA Margin for 2015. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2015, the Company was below target for Adjusted EBITDA and achieved target for Adjusted EBITDA Margin.

During 2014, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2014 and (ii) Adjusted EBITDA Margin for 2014. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2014, the Company achieved target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin.

All RSUs granted to date are subject to employment-based criteria in addition to performance criteria. Vesting occurs in December of the second calendar year following the date of grant. For example, the RSUs granted during 2014 (after adjustment for performance) vested in December 2016 to eligible employees. Although the Company has the option to settle RSUs in stock or cash at vesting, only common stock has been used to settle vested RSUs to date.

During 2016, 2015 and 2014, the Company granted RSUs to certain employees, with nearly all grants being contingent upon meeting specified performance requirements described above. The fair value of the RSUs granted in 2016, 2015 and 2014 was determined using the Company’s closing price on the grant dates.

Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2016 are eligible to vest in the year indicated in the table below:

RSUs fair value at grant date: During 2016, 2015 and 2014, the grant date fair value of RSUs granted was $9.3 million, $9.4 million and $20.1 million, respectively.

RSUs fair value at vested date: The fair value of the RSUs that vested during 2016, 2015 and 2014 was $2.4 million, $2.1 million and $2.0 million, respectively, based on the Company’s closing price on the vesting date.

The 2014 annual incentive plan award for the CEO was settled in shares of common stock based on a pre-determined price of $14.66 per share, pursuant to the terms of his award. As the number of shares could not be determined until the full-year 2014 results were determined and approved by the Compensation Committee, the CEO’s 2014 award was accounted for as a liability award and adjusted to fair value using the Company’s closing price at the end of each reporting period. The CEO award for 2014 was 100% performance based and was subject to pre-defined performance measures and employment-based criteria, which were the same pre-defined performance measures and employment-based criteria established for the other eligible employees, and were subject to approval of the Compensation Committee. An issuance of 37,316 shares of common stock was made in March 2015 to the CEO for his 2014 annual incentive compensation award. The number of shares was determined after deductions for withholding and payroll taxes and the shares were valued at the Company’s closing price as of the date of issuance.

Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2016, 2015 and 2014 to the Company’s non-employee directors as a component of their compensation arrangement. Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period. The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction period.

As of December 31, 2016, there were 317,896 shares of common stock available for issuance in satisfaction of awards under the Directors Compensation Plan. Reductions in shares available are made when Restricted Shares are granted.

Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2016 are expected to vest as follows:

Restricted stock fair value at grant date: The grant date fair value of restricted stock granted during 2016, 2015 and 2014 was $0.3 million for all periods based on the Company’s closing price on the date of grant.

Restricted stock fair value at vested date: The fair value of the restricted stock that vested during 2016, 2015 and 2014 was $0.1 million, $0.1 million and $0.3 million, respectively, based on the Company’s closing price on the date of vesting.

A summary of compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

As of December 31, 2016, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $9.7 million and $0.4 million, respectively. Unrecognized compensation expense will be recognized through November 2018 for RSUs and April 2019 for Restricted Shares.

In addition to share-based compensation, cash-based awards were granted under the Plan to substantially all eligible employees in 2016, 2015 and 2014. The cash-based awards, which are a short-term component of the Plan, are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. In addition, for the 2016 and 2015 cash-based awards, which includes the 2016/2015 incentive plan for the CEO, the Company designed the awards with an additional financial condition that must be achieved on or before December 31, 2018 for the 2016 awards, and on or before December 31, 2017 for the 2015 awards: Adjusted EBITDA less Interest Expense Incurred, as reporting by the Company in its announced Earning Release with respect to the end of any fiscal quarter plus three preceding quarters, exceeds $300.0 million. As this additional financial condition was not achieved as of December 31, 2016, no amounts were accrued or subsequently paid. If this additional financial condition is achieved, payment is to be made within 30 days following the achievement of the financial condition, but subject to all the terms of the 2016 and 2015 Annual Incentive Award Agreement (the 2016 and 2015 cash-based awards).

With respect to the 2014 cash-based awards, some of the performance criteria targets were achieved and were combined with estimates of personal performance measurements to record potential payments. Eligible employees were paid their cash-based awards within 75 days following year end 2014.

A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands):

We maintain a defined contribution benefit plan in compliance with Section 401(k) of the IRC (the “401(k) Plan”), which covers those employees who meet the 401(k) Plan’s eligibility requirements. As of March 5, 2016, the Company suspended matching contributions. From January 1, 2016 to March 5, 2016, and during 2015 and 2014, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% of the participant’s eligible compensation, subject to limitations imposed by the IRC. The 401(k) Plan provides 100% vesting in Company match contributions on a pro rata basis over five years of service (20% per year). Our expenses relating to the 401(k) Plan were $0.4 million, $2.3 million and $2.4 million for 2016, 2015 and 2014, respectively.

The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax benefit is as follows (in thousands, except percentages):

	Year Ended December 31,
	2016					2015					2014
Income tax (benefit) at the federal statutory rate	$	(102,339	)	35.0	%	$	(436,696	)	35.0	%	$	(5,642	)	35.0	%
Share-based compensation		4,920		(1.7	)		2,940		(0.2	)		—		—
State income taxes		(755	)	0.2			(2,343	)	0.2			263		(1.6	)
Valuation allowance		52,915		(18.1	)		232,925		(18.7	)		—		—
Debt restructuring cost		1,463		(0.5	)		—		—			—		—
Other		420		(0.1	)		190		—			920		(5.7	)
	$	(43,376	)	14.8	%	$	(202,984	)	16.3	%	$	(4,459	)	27.7	%

Our effective tax rate for the years 2016 and 2015 differed from the federal statutory rate of 35.0% primarily due to recording and adjusting a valuation allowance for our deferred tax assets, which is discussed below. Our effective tax rate for the year 2014 is distorted due to a small pre-tax loss; consequently, our permanent differences have a larger impact on our effective tax rate.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities were as follows (in thousands):

During 2016, we made income tax payments of $0.3 million and received $7.8 million of refunds, which includes an income tax refund of $5.8 million related to an NOL claim for 2015 carried back to 2005 filed on Form 1139, Corporation Application for Tentative Refund. During 2015, we did not make any payments for federal or state income taxes or receive any refunds of significance. During 2014, we did not make any payments for federal and state income taxes and we received refunds of $3.0 million.

As of December 31, 2016, we have recorded current income tax receivables of $11.9 million and non-current income tax receivables of $52.1 million. The current income tax receivables primarily relates to a net operating loss claim for 2016 carried back to 2006 and is included in the receivable line Joint interest, insurance reimbursement and other on the Consolidated Balance Sheet. The non-current income tax receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to the years 2003, 2004, 2007, 2010 and 2011 filed on Form 1120X, U.S. Corporation Income Tax Return. These carryback claims are made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years. The refund claims filed on Form 1120X will require a review by the Congressional Joint Committee on Taxation and are accordingly classified as non-current.

The table below presents the details of our net operating loss and tax credit carryovers as of December 31, 2016 (in thousands):

The tax gain on the Exchange Transaction associated with the cancellation of a portion of our debt was not recognized pursuant to Internal Revenue Code Section 108. Certain tax attributes including net operating losses, alternative minimum tax credit, general business credit carryovers and the tax basis of assets are required to be reduced, as reflected in the table above. No carryovers will be available to 2017.

During 2016 and 2015, we recorded increases in the valuation allowance of $52.9 million and $232.9 million, respectively, related to federal and state deferred tax assets. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. As of December 31, 2016 and 2015, we had a valuation allowance related to Federal and state deferred tax assets.

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. There are no unrecognized benefits that would impact the effective tax rate if recognized. While amounts could change in the next 12 months, we do not anticipate it having a material impact on our financial statements.

We recognize interest and penalties related to uncertain tax positions in income tax expense. For 2016, 2015 and 2014, the amounts recognized in income tax expense were immaterial.

The tax years from 2013 through 2016 remain open to examination by the tax jurisdictions to which we are subject.

The Company’s unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are deemed participating securities and are included in the computation of earnings per share under the two-class method when the effect is dilutive.

The following table presents the calculation of basic and diluted loss per common share (in thousands, except per share amounts):

	Year Ended December 31,
	2016			2015			2014
Supplemental cash items:
Cash paid for interest, net of interest capitalized of $520 in 2016, $7,256 in 2015 and $8,526 in 2014	$	96,501		$	92,622		$	77,607
Cash paid for income taxes		310			390			—
Cash refunds received for income taxes		7,796			90			3,000
Cash paid for share-based compensation ⁽¹⁾		—			—			431

Non-cash investing activities:
Accruals for property and equipment		9,129			44,324			99,750
ARO - additions, dispositions and revisions, net		10,865			(394	)		89,826

Non-cash financing activities:
Exchange transaction — non-cash securities issued:
11.00% 1.5 Lien Term Loan - interest payable		23,823			—			—
9.00%/10.75% Second Lien PIK Toggle Notes - carrying value		223,905			—			—
8.50%/10.00% Third Lien PIK Toggle Notes - carrying value		213,446			—			—
Common stock issued - fair value at issuance date		106,366			—			—

Exchange transaction — non-cash securities exchanged:
8.50% Unsecured Senior Notes - carrying value		(712,967	)		—			—

We have operating lease agreements for office space and office equipment. The lease for the majority of our office space terminates in December 2022. Minimum future lease payments due under noncancelable operating leases with terms in excess of one year as of December 31, 2016 are as follows: 2017–$1.6 million; 2018–$1.7 million; 2019–$1.8 million; 2020–$1.8 million thereafter–$3.7 million. Total rent expense was approximately $3.2 million, $3.3 million and $3.2 million during 2016, 2015 and 2014, respectively.

Pursuant to the Purchase and Sale Agreement with Total E&P, we may fulfill security requirements related to ARO for certain properties through securing bonds, or through making payments to an escrow account under a formula pursuant to the agreement, or a combination thereof, until certain prescribed thresholds are met. Once the threshold is met for that year, excess funds in the escrow account are returned to us. As of December 31, 2016, we had bonds totaling $75.0 million and had $1.9 million in an escrow account. The threshold is $83.0 million for 2017, $88.0 million for 2018 and escalates to $103.0 million for 2023 in $3.0 million per year increments.

Pursuant to the Purchase and Sale Agreement with Shell Offshore Inc. (“Shell”) related to ARO for certain properties, we have bonds that are subject to re-appraisal by either party after November 2015. As of December 31, 2016, neither party had requested a re-appraisal to be made. The current security requirement of $64.0 million could be increased up to $94.0 million depending on certain conditions and circumstances.

During 2016, 2015 and 2014, we had surety bonds related to our decommissioning obligations or ARO. Total expenses related to surety bonds, inclusive of the surety bonds in connection with the Total E&P and Shell agreements described above, were $4.3 million, $5.5 million and $4.1 million during 2016, 2015 and 2014, respectively. The amount of future commitments is dependent on rates charged in the market place and when asset retirements are completed. Estimated future expenses related to surety bonds were based on current market prices and estimates of the timing of asset retirements, of which some wells and structures are estimated to extend to 2030. Future costs are estimated as follows: 2017–$6.1 million; 2018–$5.9 million; 2019–$5.2 million; 2020–$5.0 million; thereafter–$38.6 million. See Notes 17 and 19 for information concerning financial assurances per the BOEM regulations, which could impact future cost estimates related to surety bonds.

As of December 31, 2016, we had $16.9 million of collateral deposits for certain sureties related to certain surety bonds for decommissioning obligations and appeals submitted to the Interior Board of Land Appeals (the “IBLA”).

Pursuant to an agreement with the Helix Well Containment Group, we are required to make payments quarterly in advance to have access to certain equipment to respond to a subsea spill should a spill occur at a property we operate. As of December 31, 2016, future payments due are $1.7 million in 2017 and $1.7 million in 2018. These payments may increase or decrease depending on whether the number of companies participating in the consortium changes.

We have no drilling rig commitments with a term that exceeded one year as of December 31, 2016 and our drilling rig commitments meet the criteria of an operating lease. Future payments of all drilling rig commitments as of December 31, 2016 were $7.4 million, of which $2.9 million relates to ARO projects.

During 2016, 2015 and 2014, there were certain transactions between us and other companies our CEO either controlled or in which he had an ownership interest. In addition, there were transactions with a company that employs the spouse of our CEO. Our CEO owns an aircraft that the Company used and reimbursed him for such use and for his use. Airplane services were charged to us at rates that were either equal to or below rates charged by non-related, third-party companies. Airplane services transactions were approximately $1.1 million, $1.1 million and $0.9 million for the years 2016, 2015 and 2014, respectively. Our CEO has ownership interests in certain wells operated by us (such ownership interests pre-date our initial public offering). Revenues are disbursed and expenses are collected in accordance with ownership interest. Proportionate insurance premiums were paid to us and proportionate collections of insurance reimbursements attributable to damage on certain wells were disbursed. W&T hired the services of a directional drilling services company, in which our CEO owns a minority ownership interest and serves on its board of directors. We paid no amounts in 2016 and 2015 and paid $0.2 million for drilling related services during 2014. A company that provides marine transportation and logistics services to W&T employs the spouse of our CEO. The spouse received commissions partially based on services rendered to W&T which totaled less than $0.2 million per year for 2016, 2015 and 2014. During 2015, an entity controlled by our CEO participated in the Second Lien Term Loan for a $5.0 million principal commitment on the same terms as the other lenders.

See Note 19 for a BOEM order issued in December 2016 related to additional financial assurance for sole liability properties, which was subsequently withdrawn in February 2017 by the BOEM. See Note 19 regarding a notice issued in January 2017 by the BOEM extending the implementation timeline by an additional six months of the new regulations as to non-sole liability leases, ROWs and RUEs.

The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities. Pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.

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. We received notice from the ONRR of a statutory fine of $2.3 million (subsequently reduced to $1.1 million) relative to such underpayment. We believe the fine is excessive considering the circumstances and in relation to the amount of underpayment. A hearing on this matter was held with an Administrative Law Judge in August 2016. A decision on this case has been deferred until March 2017 at the earliest. 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, 2016 or 2015.

On December 15, 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached the joint operating agreement (the “JOA”) related to, among other things, the abandonment of deepwater wells in the Mississippi Canyon area of the Gulf of Mexico. On October 28, 2016, the jury made the following findings:

In November 2016 we filed a motion with the trial court requesting a judgment consistent with the jury’s finding that Apache acted in bad faith thereby causing W&T not to comply with the contract, which W&T asserted bars Apache from recovery for damages under applicable law, and if damages are not barred in their entirety, that any judgment for monetary damages should be offset by $17.0 million as determined by the jury. After Apache filed its opposing motion, a hearing was held by the trial court in December 2016. As of the filing date of this Form 10-K, no judgment has been entered by the court.

The matter concerning certain claims with certain insurance companies was settled during the fourth quarter of 2016. See Note 5 for a description of the settlement and the accounting of the funds received. The settlement does not include claims that have not yet been made subject to adjustment or requested for reimbursement by us as of the date of the settlement.

In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the IBLA under the Department of the Interior. See Note 19 regarding the denial of our appeal subsequent to December 31, 2016.

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 for which we had gas processed. In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production that was processed through a specific processing plant. We also received a preliminary determination notice from the ONRR asserting its preliminary determination that our allocation of certain processing costs and plant fuel use at another processing plant were impermissibly allowed as deductions in the determination of royalties owed under Federal oil and gas leases. We submitted revised calculations covering certain plants and certain time periods and has not yet received official responses as to the preliminary determination asserting the reasonableness of its revised allocation methodology of such costs. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods. We have paid $0.5 million during 2016 based on our revised calculations for one plant covering part of the 84 month period. We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

During 2016 and 2015, we paid $0.1 million and $0.2 million of civil penalties issued by the BSEE related to Incidents of Noncompliance (“INCs”) issued by the BSEE at various offshore locations. We currently have four open civil penalties issued by the BSEE arising from INCs, which have not been settled as of the filing of this Form 10-K. The INC’s underlying the civil penalties were issued during 2015, with one re-issued during 2016, and relate to four separate offshore locations with occurrence dates ranging from July 2012 to June 2014. The proposed civil penalties for these INCs total $8.1 million. We have accrued approximately $1.5 million, which is our best estimate of the final settlement once all appeals have been exhausted. Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.

In August, 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board in their suit against the Company (among others) in the 18^th Judicial District Court for the Parish of Iberville, State of Louisiana. This case involves claims by the Iberville Parish School Board that certain property in Louisiana had allegedly been contaminated or otherwise damaged by certain defendants’ oil and gas exploration and production activities. The plaintiff’s claims include assessment costs, restoration costs, diminution of property value, punitive damages, and attorney fees and expenses, of which were not quantified in the claim. We cannot currently estimate our potential exposure, if any, related to this lawsuit. We are currently, and intend to continue, vigorously defending this litigation.

We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

Unaudited quarterly financial data are as follows (in thousands, except per share amounts):

	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
Year Ended December 31, 2016
Revenues	$	77,715		$	99,655		$	107,403		$	115,213
Operating income (loss) ⁽¹⁾		(166,614	)		(126,997	)		(58,276	)		21,319
Net income (loss) ⁽¹⁾		(190,509	)		(120,922	)		45,928			16,483
Basic and diluted income (loss) per common share ^{(1) (2)}		(2.49	)		(1.58	)		0.48			0.12

Year Ended December 31, 2015
Revenues	$	127,907		$	149,066		$	126,228		$	104,064
Operating loss ⁽¹⁾		(337,508	)		(278,806	)		(468,573	)		(60,816	)
Net loss ⁽¹⁾		(255,095	)		(260,449	)		(477,568	)		(51,606	)
Basic and diluted loss per common share ^{(1) (2)}		(3.36	)		(3.43	)		(6.29	)		(0.68	)

In January 2017, the IBLA stay related to our appeal of the BOEM orders issued during the first quarter of 2016 was extended to May 31, 2017.

In February 2017, the BOEM withdrew the orders it issued in December 2016 affecting so called “sole liability properties” to allow time for the new President’s administration to review the complex financial assurance program. 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. This withdrawal rescinded the Order to Provide Additional Security issued to us in December 2016. However, the BOEM may 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 liabilities.

On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties, which is described in Note 17. We are reviewing the decision with counsel to determine an appropriate course of action.

Our payment obligations under the Credit Agreement, the 1.5 Lien Term Loan, the Second Lien Term Loan, the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes and the Unsecured Senior Notes (see Note 2) are fully and unconditionally guaranteed by our 100%-owned subsidiaries, W & T Energy VI, LLC and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). W & T Energy VII, LLC does not currently have any active operations or any assets. Guarantees will be released under certain circumstances, including:

The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Included in the consolidating adjustments was an adjustment related to the ceiling test write-down, as the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company. This resulted in write-downs for the combined subsidiaries to be greater than or less than computed on a total Company basis, which required a contra ceiling test write-down adjustment to present the consolidated results appropriately.

When transfers of property were made from the Parent Company to the Guarantor Subsidiaries, which were transactions between entities under common control, the prior period financial information was retrospectively adjusted for comparability purposes, as prescribed under authoritative guidance. None of the adjustments had any effect on the consolidated results for the current or prior periods presented.

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.

Assets
Current assets:
Cash and cash equivalents	$	70,236		$	—		$	—		$	70,236
Receivables:
Oil and natural gas sales		2,173			40,900			—			43,073
Joint interest and other		163,200			—			(99,272	)		63,928
Total receivables		165,373			40,900			(99,272	)		107,001
Prepaid expenses and other assets		12,448			2,056			—			14,504
Total current assets		248,057			42,956			(99,272	)		191,741
Property and equipment – at cost:
Oil and natural gas properties and equipment		5,700,205			2,232,299			—			7,932,504
Furniture, fixtures and other		20,898			—			—			20,898
Total property and equipment		5,721,103			2,232,299			—			7,953,402
Less accumulated depreciation, depletion and amortization		5,360,137			2,045,259			953			7,406,349
Net property and equipment		360,966			187,040			(953	)		547,053
Restricted deposits for asset retirement obligations		27,371			—			—			27,371
Income tax receivables		52,097			—			—			52,097
Other assets		394,931			344,742			(728,209	)		11,464
Total assets	$	1,083,422		$	574,738		$	(828,434	)	$	829,726
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	74,306		$	6,733		$	—		$	81,039
Undistributed oil and natural gas proceeds		24,493			1,761			—			26,254
Asset retirement obligations		62,261			16,003			—			78,264
Long-term debt		8,272			—			—			8,272
Accrued liabilities		9,293			99,179			(99,272	)		9,200
Total current liabilities		178,625			123,676			(99,272	)		203,029
Long-term debt, less current maturities		1,012,455			—			—			1,012,455
Asset retirement obligations, less current portion		142,376			113,798			—			256,174
Other liabilities		408,050			—			(390,945	)		17,105
Shareholders’ equity (deficit):
Common stock		1			—			—			1
Additional paid-in capital		539,973			704,885			(704,885	)		539,973
Retained earnings (deficit)		(1,173,891	)		(367,621	)		366,668			(1,174,844	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ equity (deficit)		(658,084	)		337,264			(338,217	)		(659,037	)
Total liabilities and shareholders’ equity (deficit)	$	1,083,422		$	574,738		$	(828,434	)	$	829,726

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.

Assets
Current assets:
Cash and cash equivalents	$	85,414		$	—		$	—		$	85,414
Receivables:
Oil and natural gas sales		2,742			32,263			—			35,005
Joint interest and other		121,190			—			(99,178	)		22,012
Total receivables		123,932			32,263			(99,178	)		57,017
Prepaid expenses and other assets		25,375			1,504			—			26,879
Total current assets		234,721			33,767			(99,178	)		169,310
Property and equipment – at cost:
Oil and natural gas properties and equipment		5,682,793			2,219,701			—			7,902,494
Furniture, fixtures and other		20,802			—			—			20,802
Total property and equipment		5,703,595			2,219,701			—			7,923,296
Less accumulated depreciation, depletion and amortization		5,258,563			1,822,273			(147,589	)		6,933,247
Net property and equipment		445,032			397,428			147,589			990,049
Deferred income taxes		27,251			344			—			27,595
Restricted deposits for asset retirement obligations		15,606			—			—			15,606
Other assets		498,782			266,748			(760,068	)		5,462
Total assets	$	1,221,392		$	698,287		$	(711,657	)	$	1,208,022
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	100,282		$	9,515		$	—		$	109,797
Undistributed oil and natural gas proceeds		20,463			976			—			21,439
Asset retirement obligations		63,716			20,619			—			84,335
Accrued liabilities		11,922			99,178			(99,178	)		11,922
Total current liabilities		196,383			130,288			(99,178	)		227,493
Long-term debt, less current maturities		1,196,855			—			—			1,196,855
Asset retirement obligations, less current portion		173,105			120,882			—			293,987
Deferred income taxes		—			—			—			—
Other liabilities		329,129			—			(312,951	)		16,178
Shareholders’ equity (deficit):
Common stock		1			—			—			1
Additional paid-in capital		423,499			704,885			(704,885	)		423,499
Retained earnings		(1,073,413	)		(257,768	)		405,357			(925,824	)
Treasury stock, at cost		(24,167	)		—			—			(24,167	)
Total shareholders’ equity (deficit)		(674,080	)		447,117			(299,528	)		(526,491	)
Total liabilities and shareholders’ equity (deficit)	$	1,221,392		$	698,287		$	(711,657	)	$	1,208,022

Condensed Consolidating Statement of Operations for the Year Ended December 31, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.

Revenues	$	161,063		$	238,923		$	—		$	399,986
Operating costs and expenses:
Lease operating expenses		84,415			67,984			—			152,399
Production taxes		1,889			—			—			1,889
Gathering and transportation		9,795			13,133			—			22,928
Depreciation, depletion and amortization		73,268			112,277			8,493			194,038
Asset retirement obligations accretion		8,165			9,406			—			17,571
Ceiling test write-down of oil and natural gas properties		28,305			110,709			140,049			279,063
General and administrative expenses		24,817			34,923			—			59,740
Derivative loss		2,926			—			—			2,926
Total costs and expenses		233,580			348,432			148,542			730,554
Operating loss		(72,517	)		(109,509	)		(148,542	)		(330,568	)
Loss of affiliates		(109,853	)		—			109,853			—
Interest expense:
Incurred		92,607			184			—			92,791
Capitalized		(336	)		(184	)		—			(520	)
Gain on exchange of debt		123,923			—			—			123,923
Other (income) expense, net		(6,520	)		—			—			(6,520	)
Loss before income tax expense (benefit)		(144,198	)		(109,509	)		(38,689	)		(292,396	)
Income tax expense (benefit)		(43,720	)		344			—			(43,376	)
Net loss	$	(100,478	)	$	(109,853	)	$	(38,689	)	$	(249,020	)

Condensed Consolidating Statement of Operations for the Year Ended December 31, 2015

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.

Revenues	$	290,212		$	217,053		$	—		$	507,265
Operating costs and expenses:
Lease operating expenses		126,189			66,576			—			192,765
Production taxes		3,002			—			—			3,002
Gathering and transportation		9,209			7,948			—			17,157
Depreciation, depletion and amortization		201,154			172,214			—			373,368
Asset retirement obligations accretion		11,587			9,116			—			20,703
Ceiling test write-down of oil and natural gas properties		616,947			517,880			(147,589	)		987,238
General and administrative expenses		39,009			34,101			—			73,110
Derivative loss		(14,375	)		—			—			(14,375	)
Total costs and expenses		992,722			807,835			(147,589	)		1,652,968
Operating loss		(702,510	)		(590,782	)		147,589			(1,145,703	)
Earnings of affiliates		(464,931	)		—			464,931			—
Interest expense:
Incurred		101,542			3,050			—			104,592
Capitalized		(4,206	)		(3,050	)		—			(7,256	)
Other (income) expense, net		4,663			—			—			4,663
Loss before income tax expense		(1,269,440	)		(590,782	)		612,520			(1,247,702	)
Income tax benefit		(77,133	)		(125,851	)		—			(202,984	)
Net loss	$	(1,192,307	)	$	(464,931	)	$	612,520		$	(1,044,718	)

Condensed Consolidating Statement of Operations for the Year Ended December 31, 2014

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.

Revenues	$	571,365		$	377,343		$	—		$	948,708
Operating costs and expenses:
Lease operating expenses		180,149			84,602			—			264,751
Production taxes		7,932			—			—			7,932
Gathering and transportation		11,790			8,031			—			19,821
Depreciation, depletion and amortization		267,406			223,063			—			490,469
Asset retirement obligations accretion		10,981			9,652			—			20,633
General and administrative expenses		46,513			40,486			—			86,999
Derivative gain		(3,965	)		—			—			(3,965	)
Total costs and expenses		520,806			365,834			—			886,640
Operating income		50,559			11,509			—			62,068
Earnings of affiliates		8,320			—			(8,320	)		—
Interest expense:
Incurred		84,460			2,462			—			86,922
Capitalized		(6,064	)		(2,462	)		—			(8,526	)
Other (income) expense, net		(208	)		—			—			(208	)
Income (loss) before income tax expense (benefit)		(19,309	)		11,509			(8,320	)		(16,120	)
Income tax expense (benefit)		(7,648	)		3,189			—			(4,459	)
Net income (loss)	$	(11,661	)	$	8,320		$	(8,320	)	$	(11,661	)

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2016

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.

Operating activities:
Net loss	$	(100,478	)	$	(109,853	)	$	(38,689	)	$	(249,020	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion		81,433			121,683			8,493			211,609
Ceiling test write-down of oil and gas properties		28,305			110,709			140,049			279,063
Gain on exchange of debt		(123,923	)		—			—			(123,923	)
Debt issuance costs write-off/amortization of debt items		2,548			—			—			2,548
Share-based compensation		11,013			—			—			11,013
Derivative gain		2,926			—			—			2,926
Cash receipts on derivative settlements, net		4,746			—			—			4,746
Deferred income taxes		28,048			344			—			28,392
Loss of affiliates		109,853			—			(109,853	)		—
Changes in operating assets and liabilities:
Oil and natural gas receivables		1,630			(8,635	)		—			(7,005	)
Joint interest and other receivables		(1,126	)		—			—			(1,126	)
Income taxes		(64,274	)		—			—			(64,274	)
Prepaid expenses and other assets		(14,395	)		(78,547	)		77,996			(14,946	)
Asset retirement obligation settlements		(49,303	)		(23,017	)		—			(72,320	)
Accounts payable, accrued liabilities and other		46,955			37,538			(77,996	)		6,497
Net cash provided by (used in) operating activities		(36,042	)		50,222			—			14,180
Investing activities:
Investment in oil and natural gas properties and equipment		(37,418	)		(11,188	)		—			(48,606	)
Changes in operating assets and liabilities associated with investing activities		4,340			(39,534	)		—			(35,194	)
Proceeds from sales of assets and other, net		1,000			500			—			1,500
Purchases of furniture, fixtures and other		(96	)		—			—			(96	)
Net cash used in investing activities		(32,174	)		(50,222	)		—			(82,396	)
Financing activities:
Borrowings of long-term debt – revolving bank credit facility		340,000			—			—			340,000
Repayments of long-term debt – revolving bank credit facility		(340,000	)		—			—			(340,000	)
Issuance of 1.5 Lien Term Loan		75,000			—			—			75,000
Payment of interest on 1.5 Lien Term Loan		(2,570	)		—			—			(2,570	)
Debt exchange costs		(18,464	)		—			—			(18,464	)
Other		(928	)		—			—			(928	)
Net cash provided by financing activities		53,038			—			—			53,038
Decrease in cash and cash equivalents		(15,178	)		—			—			(15,178	)
Cash and cash equivalents, beginning of period		85,414			—			—			85,414
Cash and cash equivalents, end of period	$	70,236		$	—		$	—		$	70,236

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2015

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.

Operating activities:
Net loss	$	(1,192,307	)	$	(464,931	)	$	612,520		$	(1,044,718	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		212,741			181,330			—			394,071
Ceiling test write-down of oil and gas properties		616,947			517,880			(147,589	)		987,238
Amortization of debt issuance costs and premium		4,411			—			—			4,411
Share-based compensation		10,242			—			—			10,242
Derivative gain		(14,375	)		—			—			(14,375	)
Cash payments on derivative settlements		6,703			—			—			6,703
Deferred income taxes		(77,421	)		(125,851	)		—			(203,272	)
Loss of affiliates		464,931			—			(464,931	)		—
Changes in operating assets and liabilities:
Oil and natural gas receivables		39,078			(6,842	)		—			32,236
Joint interest and other receivables		21,633			—			—			21,633
Income taxes		(7	)		—			—			(7	)
Prepaid expenses and other assets		(13,916	)		122,977			(91,245	)		17,816
Asset retirement obligations		(26,637	)		(5,918	)		—			(32,555	)
Accounts payable, accrued liabilities and other		(141,596	)		4,156			91,245			(46,195	)
Net cash provided by (used in) operating activities		(89,573	)		222,801			—			133,228
Investing activities:
Investment in oil and natural gas properties and equipment		(31,534	)		(198,627	)		—			(230,161	)
Changes in operating assets and liabilities associated with investing activities		(29,806	)		(25,619	)		—			(55,425	)
Proceeds from sales of assets and other, net		372,939			—			—			372,939
Investment in subsidiary		(1,445	)		—			1,445			—
Purchases of furniture, fixtures and other		(1,278	)		—			—			(1,278	)
Net cash provided by (used) in investing activities		308,876			(224,246	)		1,445			86,075
Financing activities:
Borrowings of long-term debt – revolving bank credit facility		263,000			—			—			263,000
Repayments of long-term debt – revolving bank credit facility		(710,000	)		—			—			(710,000	)
Issuance of 9.00% Second Lien Term Loan		297,000			—			—			297,000
Debt issuance costs		(6,669	)		—			—			(6,669	)
Other		(886	)		—			—			(886	)
Investment from parent		—			1,445			(1,445	)		—
Net cash provided by (used in) financing activities		(157,555	)		1,445			(1,445	)		(157,555	)
Increase in cash and cash equivalents		61,748			—			—			61,748
Cash and cash equivalents, beginning of period		23,666			—			—			23,666
Cash and cash equivalents, end of period	$	85,414		$	—		$	—		$	85,414

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2014

										Consolidated
	Parent			Guarantor						W&T
	Company			Subsidiaries			Eliminations			Offshore, Inc.

Operating activities:
Net income (loss)	$	(11,661	)	$	8,320		$	(8,320	)	$	(11,661	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		278,387			232,715			—			511,102
Amortization of debt issuance costs and premium		701			—			—			701
Share-based compensation		14,744			—			—			14,744
Derivative loss		(3,965	)		—			—			(3,965	)
Cash payments on derivative settlements		(5,318	)		—			—			(5,318	)
Deferred income taxes		(32,456	)		27,696			—			(4,760	)
Earnings of affiliates		(8,320	)		—			8,320			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		19,553			9,957			—			29,510
Joint interest and other receivables		(4,255	)		—			—			(4,255	)
Income taxes		27,650			(24,507	)		—			3,143
Prepaid expenses and other assets		45,962			(7,525	)		(23,425	)		15,012
Asset retirement obligations		(57,253	)		(17,060	)		—			(74,313	)
Accounts payable, accrued liabilities and other		11,931			(30,475	)		23,425			4,881
Net cash provided by operating activities		275,700			199,121			—			474,821
Investing activities:
Acquisition of property interest in oil and natural gas properties		(17,407	)		(54,827	)		—			(72,234	)
Investment in oil and natural gas properties and equipment		(312,044	)		(242,334	)		—			(554,378	)
Changes in operating assets and liabilities associated with investing activities		1,733			35,717			—			37,450
Investment in subsidiary		(62,323	)		—			62,323			—
Purchases of furniture, fixtures and other		(3,340	)		—			—			(3,340	)
Net cash used in investing activities		(393,381	)		(261,444	)		62,323			(592,502	)
Financing activities:
Borrowings of long-term debt – revolving bank credit facility		556,000			—			—			556,000
Repayments of long-term debt – revolving bank credit facility		(399,000	)		—			—			(399,000	)
Dividends to shareholders		(30,260	)		—			—			(30,260	)
Other		(1,193	)		—			—			(1,193	)
Investment from parent		—			62,323			(62,323	)		—
Net cash provided by financing activities		125,547			62,323			(62,323	)		125,547
Increase in cash and cash equivalents		7,866			—			—			7,866
Cash and cash equivalents, beginning of period		15,800			—			—			15,800
Cash and cash equivalents, end of period	$	23,666		$	—		$	—		$	23,666

All of our proved reserves are located within the United States in the Gulf of Mexico. Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis.

Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions):

Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities

The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions):

The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold.

There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information represents estimates only and are inherently imprecise and may be subject to substantial revisions as additional information such as reservoir performance, additional drilling, technological advancements and other factors become available. Decreases in the prices of oil, NGLs and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. We are not the operator with respect to approximately 19% of our proved developed non-producing reserves as of December 31, 2016 so we may not be in a position to control the timing of all development activities. We are the operator for all of our proved undeveloped reserves as of December 31, 2016. In prior years, we were not the operator of all proved undeveloped reserves.

The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States with all located in state and federal waters in the Gulf of Mexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economic viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “Standardized Measure of Discounted Future Net Cash Flows”.

										Total Energy Equivalent Reserves ⁽¹⁾
	Oil (MMBbls)			NGLs (MMBbls)			Natural Gas (Bcf)			Oil Equivalent (MMBoe)			Natural Gas Equivalent (Bcfe)
Proved reserves as of Dec. 31, 2013		58.5			15.9			259.9			117.7			705.9
Revisions of previous estimates ⁽²⁾		1.6			0.1			14.3			4.1			25.3
Extensions and discoveries ⁽³⁾		7.3			0.7			10.1			9.7			58.1
Purchase of minerals in place ⁽⁴⁾		1.5			1.2			20.7			6.1			36.5
Production		(7.2	)		(2.1	)		(50.1	)		(17.6	)		(105.8	)
Proved reserves as of Dec. 31, 2014		61.7			15.8			254.9			120.0			720.0
Revisions of previous estimates ⁽⁵⁾		4.8			(0.9	)		4.9			4.7			28.0
Revisions related to sold properties ⁽⁶⁾		(12.1	)		(4.8	)		(2.9	)		(17.4	)		(104.3	)
Extensions and discoveries ⁽⁷⁾		2.4			0.2			8.8			4.1			24.4
Purchase of minerals in place ⁽⁸⁾		—			—			6.1			1.0			6.1
Sales of reserves ⁽⁹⁾		(13.5	)		(2.1	)		(20.2	)		(19.0	)		(113.8	)
Production		(7.8	)		(1.6	)		(46.2	)		(17.0	)		(102.3	)
Proved reserves as of Dec. 31, 2015		35.5			6.6			205.4			76.4			458.1
Revisions of previous estimates ⁽¹⁰⁾		4.6			3.1			32.1			13.0			78.1
Production		(7.2	)		(1.5	)		(39.7	)		(15.4	)		(92.2	)
Proved reserves as of Dec. 31, 2016		32.9			8.2			197.8			74.0			444.0

Year-end proved developed reserves:
2016		26.6			7.6			183.1			64.7			388.2
2015		29.4			6.4			198.5			69.0			413.5
2014		35.7			10.7			221.1			83.3			499.7

Year-end proved undeveloped reserves:
2016⁽¹¹⁾		6.3			0.6			14.7			9.3			55.8
2015		6.1			0.2			6.9			7.4			44.6
2014		26.0			5.1			33.8			36.7			220.3

The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the crude oil realized price. Then, this ratio is applied to the crude oil price using FASB/SEC guidance. The average commodity prices weighted by field production and after adjustments related to the proved reserves are as follows:

Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on a 10% annual discount rate.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2016 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):

The change in the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):

	Year Ended December 31,
	2016			2015			2014
Changes in Standardized Measure
Standardized measure, beginning of year	$	613.9		$	1,702.8		$	1,674.6
Increases (decreases):
Sales and transfers of oil and gas produced, net of production costs		(218.6	)		(289.1	)		(650.9	)
Net changes in price, net of future production costs		(275.2	)		(1,455.6	)		(278.6	)
Extensions and discoveries, net of future production and development costs		—			65.3			309.6
Changes in estimated future development costs		(32.5	)		(8.5	)		(56.4	)
Previously estimated development costs incurred		114.5			158.9			263.1
Revisions of quantity estimates		190.1			137.9			118.6
Accretion of discount		52.6			150.6			180.6
Net change in income taxes		—			600.8			(11.4	)
Purchases of reserves in-place		—			6.0			86.7
Sales of reserves in-place		—			(401.4	)		—
Changes in production rates due to timing and other		33.5			(53.8	)		66.9
Net increase (decrease) in standardized measure		(135.6	)		(1,088.9	)		28.2
Standardized measure, end of year	$	478.3		$	613.9		$	1,702.8

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that any information relating to us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of December 31, 2016 our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2016, is set forth in “Management’s Report on Internal Control over Financial Reporting” included under Part II, Item 8 in this Form 10-K.

The effectiveness of our internal control over financial reporting as of December 31, 2016, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included under Part II, Item 8 in this Form 10-K.

There have been no changes in our internal control over financial reporting that occurred during the quarterly period ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

All schedules are omitted because they are not applicable, not required or the required information is included in the consolidated financial statements or related notes.

Exhibit Number		Description
10.31		Priority Confirmation Joinder, dated as of September 7, 2016, by and between Toronto Dominion (Texas) LLC, as Priority Lien Agent, Morgan Stanley Senior Funding, Inc., as Second Lien Collateral Trustee, and Wilmington Trust, National Association, as Third Lien Trustee and Third Lien Collateral Trustee (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

10.32*		Form of Executive Annual Incentive Agreement for Fiscal 2015 (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q, filed November 6, 2015 (File No. 001-32414))

10.33*		Form of 2015 Executive Restricted Stock Unit Agreement (Incorporated by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K, filed March 9, 2016 (File No. 001-32414))

10.34*		Form of Executive Annual Incentive Agreement for Fiscal 2016 (Incorporated by reference to Exhibit 10.9 of the Company’s Quarterly Report on Form 10-Q, filed November 3, 2016 (File No. 001-32414))

10.35*		Form of 2016 Executive Restricted Stock Unit Agreement (Incorporated by reference to Exhibit 10.10 of the Company’s Quarterly Report on Form 10-Q, filed November 3, 2016 (File No. 001-32414))

12.1**		Ratio of Earnings to Fixed Charges

14.1		W&T Offshore, Inc. Code of Business Conduct and Ethics (as amended). (Incorporated by reference to Exhibit 14.1 of the Company’s Current Report on Form 8-K, filed November 17, 2005)

21.1**		Subsidiaries of the Registrant.

23.1**		Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.

23.2**		Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

31.1**		Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

31.2**		Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

32.1**		Certification of Chief Executive Officer and Chief Financial Officer of W&T Offshore, Inc. pursuant to 18 U.S.C. § 1350.

99.1**		Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Schema Document.

101.CAL**		XBRL Calculation Linkbase Document

101.DEF**		XBRL Definition Linkbase Document.

101.LAB**		XBRL Label Linkbase Document.

101.PRE**		XBRL Presentation Linkbase Document.

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry that are used in this report.

Acquisitions. Refers to acquisitions, mergers or exercise of preferential rights of purchase.

Bcfe. One billion cubic feet equivalent, determined using an energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

BOEM. Bureau of Ocean Energy Management. The agency is responsible for managing development of the nation’s offshore resources in an environmentally and economically responsible way. Previously, this function was managed by the Bureau of Ocean Energy Management, Regulation and Enforcement.

BOEMRE. Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the Minerals Management Service), was the federal agency that manages the nation’s natural gas, oil and other mineral resources on the outer continental shelf. The BOEMRE was split into three separate entities: the Office of Natural Resources Revenue; the Bureau of Ocean Energy Management; and the Bureau of Safety and Environmental Enforcement.

BSEE. Bureau of Safety and Environmental Enforcement. The agency is responsible for enforcement of safety and environmental regulations. Previously, this function was managed by the Bureau of Ocean Energy Management, Regulation and Enforcement.

Deep shelf well. A well drilled on the outer continental shelf to subsurface depths greater than 15,000 feet and water depths of less than 500 feet.

Deterministic estimate. Refers to a method of estimation whereby a single value for each parameter in the reserves calculation is used in the reserves estimation procedure.

Developed reserves. Oil and natural gas reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development project. A project by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Economically producible. Refers to a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Mcfe. One thousand cubic feet equivalent, determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil or other hydrocarbon.

MMcfe. One million cubic feet equivalent, determined using an energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil condensate or natural gas liquids.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGLs. Natural gas liquids. These are created during the processing of natural gas.

Non-productive well. A well that is found not to have economically producible hydrocarbons.

OCS block. A unit of defined area for purposes of management of offshore petroleum exploration and production by the BOEM.

ONRR. Office of Natural Resources Revenue. The agency assumed the functions of the former Minerals Revenue Management Program, which had been renamed to the Bureau of Ocean Energy Management, Regulation and Enforcement.

Probabilistic estimate. Refers to a method of estimation whereby the full range of values that could reasonably occur for each unknown parameter in the reserves estimation procedure is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Productive well. A well that is found to have economically producible hydrocarbons.

Proved reserves. 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. As used in

this definition, “existing economic conditions” include prices and costs at which economic production from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(22) of Regulation S-X.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

PV-10 value. A term used in the industry that is not a defined term in generally accepted accounting principles. We define PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our independent petroleum consultant using a discount rate of 10%. This amount includes projected revenues, estimated production costs and estimated future development costs. PV-10 excludes cash flows for asset retirement obligations, general and administrative expenses, derivatives, debt service and income taxes.

Reasonable certainty. When deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities of hydrocarbons will be recovered. When probabilistic methods are used, reasonable certainty means at least a 90% probability that the quantities of hydrocarbons actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience, engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

Recompletion. The completion for production of an existing well bore in another formation from that which the well has been previously completed.

Reliable technology. A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves. Estimated remaining quantities of oil, natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering the oil, natural gas or related substances to market, and all permits and financing required to implement the project.

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

Undeveloped reserves. Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic production at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 2, 2017.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 2, 2017.

Texas		72-1121985
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

Nine Greenway Plaza, Suite 300 Houston, Texas		77046-0908
(Address of principal executive offices)		(Zip Code)

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.00001		New York Stock Exchange

Volume measurements:
Boe – barrel of oil equivalent			Mcf – thousand cubic feet
MBbls – thousand barrels for crude oil, condensate or NGLs			MMcf – million cubic feet
MBoe – thousand barrels of oil equivalent			MMcfe – million cubic feet of gas equivalent

Volume measurements:
Boe – barrel of oil equivalent			Mcf – thousand cubic feet
MBbls – thousand barrels for crude oil, condensate or NGLs			MMcf – million cubic feet
MBoe – thousand barrels of oil equivalent			MMcfe – million cubic feet of gas equivalent

Volume measurements:
MMBbls – million barrels for crude oil, condensate or NGLs		Bcf – billion cubic feet
MMBoe – million barrels of oil equivalent		Bcfe – billion cubic feet of gas equivalent

Large accelerated filer	☐	Accelerated filer	☑

Non-accelerated filer	☐	Smaller reporting company	☐

		Page
Item 1.	Business		1
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		32
Item 2.	Properties		33
Item 3.	Legal Proceedings		46
	Executive Officers of the Registrant		49
Item 4.	Mine Safety Disclosures		50
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		50
Item 6.	Selected Financial Data		53
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		58
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		81
Item 8.	Financial Statements and Supplementary Data		82
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		139
Item 9A.	Controls and Procedures		139
Item 9B.	Other Information		139
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		140
Item 11.	Executive Compensation		140
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		140
Item 13.	Certain Relationships and Related Transactions, and Director Independence		140
Item 14.	Principal Accountant Fees and Services		140
PART IV
Item 15.	Exhibits and Financial Statement Schedules		141
Signatures			149
Index to Consolidated Financial Statements			82
Glossary of Oil and Natural Gas Terms			146

	December 31, 2016
Present value of estimated future net revenues (PV-10)	$	755
Present value of estimated ARO, discounted at 10%		(277	)
PV-10 after ARO		478
Future income taxes, discounted at 10% ⁽¹⁾		—
Standardized measure of discounted future net cash flows	$	478

	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Shelf		419,077		270,583		76,642		76,642		495,719		347,225
Deepwater		153,423		63,306		110,698		42,005		264,121		105,311
Total		572,500		333,889		187,340		118,647		759,840		452,536

Offshore Wells	Oil Wells ⁽¹⁾				Gas Wells ⁽¹⁾				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Operated		83		74		55		39		138		113
Non-operated		31		8		28		9		59		17
Total offshore wells		114		82		83		48		197		130

Name	Age ⁽¹⁾		Position
Tracy W. Krohn		62	Founder, Chairman, Director and Chief Executive Officer
Jamie L. Vazquez		56	President
John D. Gibbons		63	Senior Vice President and Chief Financial Officer
Thomas P. Murphy		54	Senior Vice President and Chief Operations Officer
Stephen L. Schroeder		54	Senior Vice President and Chief Technical Officer
Thomas F. Getten		69	Vice President, General Counsel and Secretary

	High		Low
2016:
First Quarter	$	7.48	$	1.23
Second Quarter		2.74		1.93
Third Quarter		2.35		1.51
Fourth Quarter		3.47		1.31

2015:
First Quarter		7.28		5.08
Second Quarter		6.80		5.24
Third Quarter		5.42		2.86
Fourth Quarter		4.00		2.05

Volume measurements:
Bbl – barrel		Mcf – thousand cubic feet
Boe – barrel of oil equivalent		MMcf – million cubic feet
MBbls – thousand barrels for crude oil, condensate or NGLs		MMcfe – million cubic feet equivalent
MBoe – thousand barrels of oil equivalent

	Closing on
	September 7, 2016
8.50% Unsecured Senior Notes, due June 2019, exchanged - Principal	$	710,171

Secured Debt Issued (principal):
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020		159,763
8.50%/10.00% Third Lien PIK Toggle Notes due June 2021		142,031
Subtotal		301,794

Reduction of debt principal	$	408,377

	Completed
	2016		2015		2014
Offshore - gross wells drills:
Conventional shelf		—		—		3
Deepwater		1		5		3
Wells operated by W&T		—		—		4

		Page
Management’s Report on Internal Control over Financial Reporting		83
Report of Independent Registered Public Accounting Firm		84
Report of Independent Registered Public Accounting Firm		85
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2016 and 2015		86
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014		87
Consolidated Statements of Changes in Shareholders’ Equity (Deficit) for the years ended December 31, 2016, 2015 and 2014		88
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014		89
Notes to Consolidated Financial Statements		90

		December 31,
	Hierarchy	2016		2015
11.00% 1.5 Lien Term Loan, due November 2019	Level 2	$	75,000	$	—
9.00 % Second Lien Term Loan, due May 2020	Level 2		255,000		217,500
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020	Level 2		122,255		—
8.50%/10.00% Third Lien PIK Toggle Notes due June 2021	Level 2		80,243		—
8.50% Unsecured Senior Notes, due June 2019	Level 2		123,389		324,000

Cash consideration:
Evaluated properties including equipment	$	18,693
Non-cash consideration:
Asset retirement obligations - non-current		6,124
Total consideration	$	24,817

Cash consideration:
Evaluated properties including equipment	$	52,347
Unevaluated properties		2,660
Sub-total cash consideration		55,007
Non-cash consideration:
Asset retirement obligations - current		782
Asset retirement obligations - non-current		10,543
Sub-total non-cash consideration		11,325
Total consideration	$	66,332

	(unaudited)
	December 31, 2014 ^(a)
Revenue	$	971,595
Net loss		(5,504	)
Basic and diluted loss per common share		(0.08	)

	(unaudited)
	December 31, 2014 ^(a)
Revenues ^(b)	$	22,887
Direct operating expenses ^(b)		4,417
DD&A ^(c)		8,385
G&A ^(d)		300
Interest expense ^(e)		330
Capitalized interest ^(f)		(19	)
Income tax expense ^(g)		3,316

	Restricted Stock Units
2017		2,311,434
2018		3,795,814
Total		6,107,248

	Amount		Expiration Year
Federal net operating loss	$	—	N/A
State net operating losses		112,512	2021-2030
Alternative minimum tax credit		—	N/A
General business credit		—	N/A

Exhibit Number		Description

2.1		Purchase and Sale Agreement, dated as of August 31, 2015, by and among Ajax Resources, LLC, as Buyer, and W&T Offshore, Inc., as Seller (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed October 21, 2015 (File No. 001-32414))

3.1		Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006 (File No. 001-32414))

3.2		Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

3.3		Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012 (File No. 001-32414))

3.4		Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc., dated as of September 6, 2016 (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed September 6, 2016 (File No. 001-32414))

4.1		Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

4.2		Indenture, dated as of June 10, 2011, by and among W&T Offshore, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 15, 2011 (File No. 001-32414))

4.3		First Supplemental Indenture, dated as of June 10, 2011, by and among W&T Offshore, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 15, 2011 (File No. 001-32414))

4.4		Form of 8.50% Senior Notes due 2019 (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K, filed June 15, 2011 (File No. 001-32414))

4.5		First Supplemental Indenture, dated as of September 7, 2016, by and among W&T Offshore, Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

Exhibit Number		Description
4.6		9.00% / 10.75% Senior Second Lien PIK Toggle Notes due 2020 Indenture, dated as of September 7, 2016, by and among W&T Offshore, Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

4.7		Form of 9.00% / 10.75% Senior Second Lien PIK Toggle Notes due 2020 (included in Exhibit 4.2) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

4.8		8.50% / 10.00% Senior Third Lien PIK Toggle Notes due 2021 Indenture, dated as of September 7, 2016, by and among W&T Offshore, Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

4.9		Form of 8.50% / 10.00% Senior Third Lien PIK Toggle Notes due 2021 (included in Exhibit 4.4) (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

4.10		Registration Rights Agreement, dated as of September 7, 2016, by and among W&T Offshore, Inc. and the initial holders named therein (Incorporated by reference to Exhibit 4.6 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

10.1*		2004 Directors Compensation Plan of W&T Offshore, Inc. (Incorporated by reference to Exhibit 10.11 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

10.2*		Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and Stephen L. Schroeder, dated July 5, 2006 (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed July 12, 2006 (File No. 001-32414))

10.3*		Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and John D. Gibbons, dated as of February 26, 2007 (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed February 26, 2007 (File No. 001-32414))

10.4*		Indemnification and Hold Harmless Agreement, dated September 24, 2008, by and between W&T Offshore, Inc. and Jamie L. Vazquez (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K, filed September 26, 2008 (File No. 001-32414))

10.5*		W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A, filed April 2, 2010 (File No. 001-32414))

10.6*		First Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed April 3, 2013)

10.7*		Second Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed April 3, 2013)

Exhibit Number		Description
10.8*		Third Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed March 24, 2016)

10.9*		Form of Employment Agreement for Executive Officers other than the Chief Executive Officer (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 6, 2010 (File No. 001-32414))

10.10*		Employment Agreement between W&T Offshore, Inc. and Tracy W. Krohn dated as of November 1, 2010 (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on November 5, 2010 (File No. 001-32414))

10.11*		Form of Indemnification and Hold Harmless Agreement between W&T Offshore, Inc. and each of its directors (Incorporated by reference to Exhibit 10.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 001-32414))

10.12*		Form of Employment Agreement by and between W&T Offshore, Inc. and Thomas P. Murphy (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed August 6, 2010 (File No. 001-32414))

10.13*		Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and Thomas P. Murphy, dated as of June 19, 2012 (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed June 22, 2012 (File No. 001-32414))

10.14*		Tracy W. Krohn Executive Annual Incentive Award Agreement for Fiscal 2013 (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q, filed August 8, 2013 (File No. 001-32414))

10.15		Fifth Amended and Restated Credit Agreement, dated as of November 8, 2013, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed November 13, 2013 (File No. 001-32414))

10.16*		Form of Executive Annual Incentive Agreement for Fiscal 2014 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q, filed May 8, 2014 (File No. 001-32414))

10.17*		Form of 2014 Executive Restricted Stock Unit Agreement (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q, filed May 8, 2014 (File No. 001-32414))

10.18*		Tracy W. Krohn Executive Annual Incentive Agreement for Fiscal 2014 (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q, filed May 8, 2014 (File No. 001-32414))

10.19		First Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 23, 2015, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent, and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed April 27, 2015 (File No. 001-32414))

10.20		Second Amendment to Fifth Amended and Restated Credit Agreement, dated as of May 8, 2015, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed May 14, 2015 (File No. 001-32414))

Exhibit Number		Description
10.21		Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 30, 2015, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed November 5, 2015 (File No. 001-32414))

10.22		Fourth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of July 28, 2016, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 3, 2016 (File No. 001-32414))

10.23		Fifth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of August 25, 2016, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as administrative agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 31, 2016 (File No. 001-32414))

10.24		$300,000,000 Term Loan Agreement, dated May 11, 2015, by and among W&T Offshore, Inc., Morgan Stanley Senior Funding, Inc., as administrative agent and collateral trustee, and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed May 14, 2015 (File No. 001-32414))

10.25		Intercreditor Agreement, dated May 11, 2015, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as priority lien agent, Morgan Stanley Senior Funding, Inc., as second lien collateral trustee, and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed May 14, 2015 (File No. 001-32414))

10.26		Form of Support Agreement, effective July 25, 2016, by and among W&T Offshore, Inc. and certain Supporting Noteholders (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed July 25, 2016 (File No. 001-32414))

10.27		Form of Amendment to Support Agreement by and among the Company and the Supporting Noteholders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 16, 2016 (File No. 001-32414))

10.28		1.5 Lien Term Loan Credit Agreement, dated as of September 7, 2016, by and among W&T Offshore, Inc., Cortland Capital Market Services LLC, as Administrative Agent and 1.5 Lien Collateral Agent, and the various lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

10.29		Priority Confirmation Joinder, dated as of September 7, 2016, by and between Toronto Dominion (Texas) LLC, as Priority Lien Agent, Cortland Capital Market Services LLC, as Administrative Agent and 1.5 Lien Collateral Agent, and Morgan Stanley Senior Funding, Inc., as Second Lien Collateral Trustee (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

10.30		Priority Confirmation Joinder, dated as of September 7, 2016, by and between Toronto Dominion (Texas) LLC, as Priority Lien Agent, Wilmington Trust, National Association, as Second Lien Trustee, and Morgan Stanley Senior Funding, Inc., as Second Lien Collateral Trustee (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

W&T OFFSHORE, INC.
By:		/s/ John D. Gibbons
		John D. Gibbons
		Senior Vice President and Chief Financial Officer

/s/ Tracy W. Krohn		Chairman, Chief Executive Officer and Director
Tracy W. Krohn		(Principal Executive Officer)
/s/ John D. Gibbons		Senior Vice President and Chief Financial Officer
John D. Gibbons		(Principal Financial and Accounting Officer)
/s/ Virginia Boulet		Director
Virginia Boulet
/s/ Stuart B. Katz		Director
Stuart B. Katz
/s/ S. James Nelson, Jr		Director
S. James Nelson, Jr.
/s/ B. Frank Stanley		Director
B. Frank Stanley