UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 20172020

or

For the transition period from                      to                     

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

(713) 626-8525

(Registrant’s telephone number, including area code)

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

Securities registeredRegistered pursuant to Section 12(g) of the Act:

None

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

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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑ 

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 $182,243,000 approximately $213,418,732 based on the closing sale price of $1.96$2.28 per share as reported by the New York Stock Exchange on June 30, 2017.2020.

The number of shares of the registrant’s common stock outstanding on February 28, 20182021 was 139,091,289.142,304,770.

DOCUMENTS INCORPORATED BY REFERENCE

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

W&T OFFSHORE, INC.

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (“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.

iiGLOSSARY OF OIL AND NATURAL GAS TERMS

PARTThe following are abbreviations and definitions of terms commonly used in the oil and natural gas industry that may be used in this Annual Report on Form 10-K.

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

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet.

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.

Boe. Barrel of oil equivalent.

Boe/d. Barrel of oil equivalent per day.

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.

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.

Conventional shelf well. A well drilled in water depths less than 500 feet.

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.

Deepwater. Water depths greater than 500 feet in the Gulf of Mexico.

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. 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.

Extension well. A well drilled to extend the limits of a known reservoir.

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

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

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet.

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.

Mcfe/d. One thousand cubic feet equivalent per day.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

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.

Oil. Crude oil and condensate.

OCS. Outer continental shelf.

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 properties. Properties with proved reserves.

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.

PV-10. 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.

Sub-salt. A geological layer lying below the salt layer.

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.

Unproved properties. Properties with no proved reserves.

PART I

Item 1. Business

W&T Offshore, Inc. is an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties 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.

We

Since our founding in 1983 by our Chairman and CEO, Tracy Krohn, we have continually grown our footprint in the Gulf of Mexico through acquisitions, exploration and development anddevelopment.  We currently hold working interests in 4943 offshore producing fields in federal and state waters (47 producingwaters.  Our acreage, well, production and two fields capable of producing).  We currently havereserves information is described in more detail under lease approximately 700,000 gross acres (370,000 net acres) spanning across the Outer Continental Shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 470,000 gross acres on the conventional shelf and approximately 230,000 gross acresPart I Item 2, Properties, in the deepwater.  A majority of our daily production is derived from wells we operate.  We currently ownthis Form 10-K.  Our working interests in approximately 135 offshore structures, 87 of which are located in fields that we operate.  Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiary, W & T&T Energy VI, LLC, a Delaware limited liability company.company and through our proportionately consolidated interest in Monza Energy, LLC (“Monza”), as described in more detail in Financial Statements and Supplementary Data – Note 4 – Joint Venture Drilling Program under Part II, Item 8 in this Form 10-K.  

The Gulf of Mexico is an area where we

We have developed significant technical expertise in finding and where highdeveloping properties in the Gulf of Mexico with production rates associated with hydrocarbon deposits have historically provided uswhich provide 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).shelf.  We have acquired rights to explore and develop new prospects and 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.  Our drilling efforts in recent years have included the deepwater of the Gulf of Mexico. During 2017

Business Strategy

Our goal is to pursue high rate of return projects and 2016, a portion of our production was from the deepwater fields, Big Bend and Dantzler, which commenced production in late 2015.  The reserves of both of these are comprised of over 75%develop oil and natural gas liquids (“NGLs”)resources that allow us to grow our production, reserves and cash flow in a capital efficient manner, thus enhancing the value of our assets. We intend to execute the following elements of our business strategy in order to achieve this goal:

Our focus is on a Boe basis.  As of December 31, 2017, the Big Bend field was inmaking profitable investments while operating within cash flow, maintaining sufficient liquidity, cost reductions and fulfilling our top ten fields based on reserves, netcontractual, legal and financial obligations.  Over time, we expect to de-lever through free cash flow generated by our producing asset base, capital discipline, organic growth and acquisitions. We continue to closely monitor current and forecasted commodity prices to assess if changes are needed to our interest, on a Boe basis.plans. 

Market Trends

In managing our business, we are focused on optimizing production and growingincreasing reserves in a profitable and prudent manner, while managing cash flows to meet our obligations and investment needs.  Our cash flows are materially impacted by the prices of our commodities producedwe produce (crude oil, and natural gas and the NGLsnatural gas liquids ("NGLs") extracted from the natural gas).  In addition, the prices of goods and services used in our business can vary and impact our cash flowsflows.

COVID-19 Impacts on Economic Environment.  Due to circumstances related to the outbreak of COVID-19, various measures have been taken by federal, state and margins.  local governments to reduce the rate of spread of COVID-19.  These measures and other factors have resulted in a decrease of general economic activity and a corresponding decrease in global and domestic energy demand impacting commodity pricing.  In addition, actions by the Organization of Petroleum Exporting Countries and other high oil exporting countries like Russia (“OPEC+”) negatively impacted crude oil prices during early 2020.  These rapid and unprecedented events pushed crude oil storage near capacity and drove prices down significantly in the second quarter of 2020.  These events were the primary cause of the significant supply-and-demand imbalance for oil, significantly lowering oil pricing in 2020 compared to the prior year.  Throughout the United States during 2020, COVID-19 outbreaks continued and, in some areas, increased.  Should these conditions continue in future periods, they could constrain our ability to store and move production to downstream markets, delay or curtail development activity or temporarily shut-in production, any or all of which could further reduce our cash flow.

Hurricanes Impact on our Production.  Beginning in the second quarter of 2020 and extending through October 2020, the Gulf of Mexico experienced numerous hurricanes and tropical storms that required us to shut-in production at times due to their impact.  We have since returned substantially all wells to production that were shut-in due to the hurricanes and tropical storms, as have operators of properties in which we have an interest.  While no major structural damage occurred, we incurred $4.7 million in repairs costs during 2020 associated with repairs to our assets caused by storm events in 2020. See “Risk Factors” – “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.”

During 2017,2020, average realized commodity prices improveddecreased from the lower price levelsthose we experienced during 2016 and 2015, but were nonetheless below the levels realized in years prior to 2015.2019.  Our margins in 2017 have improved2020 decreased from 2016 and 2015 levels, and are approaching the margin levels achieved prior2019 primarily due to 2015.  Although we have historically grown our reserves and production through both acquisitions and our drilling programs, for the last three years we have focused on increasing reserves and production through drilling and through projects to optimize production from existing wells.  While our production decreased 5.2% in 2017 from the prior year, our reserves increased more than production and resulted in a net increase in reserves year-over-year.  The increase in proved reserves islower average realized commodity prices, partially offset by lower operating expenses as a result of drilling, recompletionour cost-cutting efforts in 2020.  We measure margins using net income (loss) before net interest expense; income tax (benefit) expense; depreciation, depletion, amortization and workover effects,accretion; unrealized commodity derivative gain or loss; amortization of derivative premiums; bad debt reserve; gain on debt transaction; litigation; and improved commodity prices.  During 2017, we drilled five wells on the continental shelf, fourother (“Adjusted EBITDA”) as a percent of revenue, which were successful and began producing during 2017.

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultants, our total proved reserves at December 31, 2017 were 74.2 million barrels of oil equivalent (“MMBoe”) or 445.3 billion cubic feet of gas equivalent (“Bcfe”) compared to 74.0 MMBoe as of December 31, 2016.  Approximately 74% of our proved reserves as of December 31, 2017 were classified as proved developed producing, 10% as proved developed non-producing and 16% as proved undeveloped.  Classified by product, our proved reserves at December 31, 2017 were 46% crude oil, 11% NGLs and 43% 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 $992.9 million before consideration of cash outflows related to asset retirement obligations (“ARO”).  Our PV-10 after considering future cash outflows related to ARO was $800.7 million, and our standardized measure of discounted future cash flows was $740.6 million as of December 31, 2017.  Neither PV-10 nor PV-10 after ARO is a not a financial measure definedmeasurement under generally accepted accounting principles (“GAAP”).  For additional information about our

To provide additional financial flexibility, as we have previously reported, throughout 2017 and now into 2018 we have been working to establish a drilling joint venture with private investors.  We are in final stages of establishing a drilling joint venture to be formed with private investors that will allow us to drill and exploit assets on a promoted basis and with reduced capital outlay.  We have completed negotiations with an initial group of investors, the terms of which are subject to funding at an initial closing expected to occur by mid-March.  It is expected that entities owned and controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family will invest on the same terms as are negotiated with the unaffiliated investors to acquire an approximate 4% interest in the drilling joint venture.  More investors may join the joint venture before or after the initial closing.  If completed, this joint venture arrangement should reduce cash commitments for capital expenditures depending on the level of outside investor participation. We believe other arrangements on a promoted basis are available in the current market environment.  We believe financing arrangements exist for the right acquisition opportunity, although these financing arrangements may be structured differently than past arrangements.  

We also expect to reduce or extend the maturities of a significant amount of our existing indebtedness within the next 12 months assuming reasonably stable market conditions to provide greater financial flexibility.  Our 2018 plans include spending $24 million for ARO, compared to $72 million spent on ARO in 2017.  We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 20182021 plans.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.

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.  During 2017, we did not drill or participate in any deepwater projects, and in 2016, we participated in one deepwater project.  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 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.

Business Strategy

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.  We believe attractive drilling and 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, establishing a drilling joint venture to provide drilling capital on a promoted basis (as discussed above) and pursuing acquisitions meeting our criteria.

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. 

Competition

The oil and natural gas industry is highly competitive.  We also face increasing indirect competition from alternative energy sources, including wind, solar, and electric power. We currently operate in the Gulf of Mexico and compete for the acquisition of oil and natural gas properties and lease sales 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, acquire additional leases and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties, finance investments and consummate transactions in a highly competitive environment.

Oil and Natural Gas Marketing and Delivery Commitments

We sell our crude oil, NGLs and natural gas to third-party customers.  We are not dependent upon, or contractually limited to, any one customer or small group of customers.  However, in 2017,2020, approximately 46%39% of our salesrevenues were received from BP Products North America, 13% to ShellWilliams Field Services and 10% to Mercuria Energy America Inc. Trading (US) Co. and 15% were to Vitol Inc., with no other customer comprising greater than 10% of our 20172020 revenues. Due toGiven the free tradingcommoditized nature of the oilproducts we produce and natural gas marketsmarket and the location of our production in the Gulf of Mexico, we do not believe the loss of any of the customers above would not result in a single customer or a few customers would materially affectmaterial adverse effect on our ability to sell our production.market future oil and natural gas, 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 do not have any agreements which obligate us to deliver material quantitiesa fixed volumes of physical products to third parties.customers. 

Exchange Transaction in 2016

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.

Regulation 

Compliance with Government Regulations

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”), both agencies under the U.S. Department of the Interior (“DOI”), have adopted regulations pursuant to the Outer Continental Shelf Lands Act (“OCSLA”), that 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 nonpricenon-price 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 FERC also regulates rates and service conditions for the interstate transportation of liquids, including crude oil, condensate and NGLs, under various statues.statutes.

The Federal Trade Commission (“FTC”), 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-relatedmarket 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.  Any violation of the FTC, FERC, and CFTC prohibitions on market manipulation can result in substantial civil penalties amounting to over $1$1.0 million per violation per day.

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.

Federal leases.  Most of our offshore operations are conducted on federal oil and natural gas leases.leases in the OCS waters of the Gulf of Mexico.  The DOI has delegated its authority to issue federal leases granted under the OCSLA to the BOEM, which has adopted and implemented regulations relating to the issuance and operation of oil and natural gas leases on the OCS. These leases are awarded by the BOEM based on competitive bidding and contain relatively standardized terms. These leases require compliance with the BOEM, the BSEE, and other government agency regulations and orders that are subject to interpretation and change.  The BOEM and BSEE also regulateregulates 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”).  , while the BOEM governs financial assurance requirements associated with those decommissioning obligations.

President Biden entered office in January 2021 and has made tackling climate change, including the restriction or elimination of future greenhouse gases (“GHGs”), a priority in his administration.  The Biden Administration has already adopted several executive orders and is expected to pursue additional orders and pursue legislation, regulations or other regulatory initiatives in support of this regulatory agenda.  Notably, the Acting Secretary of the U.S. Department of the Interior issued an order on January 20, 2021, effective immediately, that suspends new oil and gas leases and drilling permits on federal lands and offshore waters, including the OCS for a period of 60 days. Building on this suspension, President Biden issued an executive order on January 27, 2021 that suspends new leasing activities for oil and gas exploration and production on federal lands and offshore waters pending review and reconsideration of federal oil and gas permitting and leasing practices.  While these January 20, 2021 and January 27, 2021 orders do not apply to existing leases, the January 27, 2021 order further directs applicable agencies to take measures to eliminate provision of subsidies to the fossil fuel industry, although the term "subsidies" is not defined by the adminstration.  We continue to conduct our operations on our existing leases in the OCS; however, uncertainty on future Biden Administration actions with regards to offshore oil and gas activities on the OCS together with the issuance of any future executive orders or adoption and implementation of laws, rules or initiatives that further restrict, delay or result in cancellation of existing oil and gas activities on the OCS could have a material adverse effect on our business and operations.

Decommissioning and financial assurance requirements.  The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations orand provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.  In July 2016, the BOEM under the Obama Administration issued Notice to Lessees and Operators (“NTL”) #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”).  While NTL #2016-N01 became effective in September 2016, butit was not fully implemented as the BOEM under the Trump Administration first extended indefinitely in 2017 implementation of the NTL and subsequently rescinded the NTL in the latter half of 2020, instead electing to publish in October 2020 a proposed rule that would amend the BOEM’s financial assurance requirements.  The Biden Administration is expected to review and reconsider actions made under the Trump Administration with respect to provision of financial assurance, including the rescission of NTL #2016-N01 and publication of the October 2020 proposed rulemaking.  Any issuance by the Biden Administration of more stringent NTL guidance or rules relating to the provision of additional financial assurance may have a material adverse effect on us and similarly situated offshore oil and gas operators on the OCS.  Moreover, the BOEM has since extended indefinitely the start date for implementation.  In December 2016, we received an Orderauthority to Provide Additional Security from the BOEM totaling approximately $29.5 million for our sole liability properties (the “December 2016 Order”).  However, following the BOEM’s action in January 2017 to extend the implementation date of NTL #2016-N01 for a period of six months, the BOEM elected to include sole liability properties as being covered under the extension and thus issued us a letter on February 21, 2017 rescinding the December 2016 Order while the BOEM reviewed its financial assurance program.  In June 2017, the BOEM further extended the start date for implementing NTL #2016-N01 indefinitely beyond June 30, 2017.  This extension currently remains in effect; however, the BOEM reserved the right to re-issue soleissue liability orders in the future, including in the event thatif 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,Under applicable BSEE regulations, lessees operating on the BSEE issued a final rule requiring lesseesOCS and conducting decommissioning activities are required to submit summaries of actual expenditures for decommissioning of subject wells, platforms, and other facilities required under the BSEE’s existing regulations.facilities. The BSEE has reported that it will useuses 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”)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.  Through December 31, 2017, we have paid $ 2.1 million in additional royalties as a result of this initiative.  

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 resultseffect 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, thatwhich 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,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 liquids, which include 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.  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, condensate, 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.

Compliance with Environmental Regulations

General.  We are subject to complex and stringent federal, state and local environmental laws.  These laws, among other things, govern the issuance of permits to conduct exploration, drilling and producingproduction operations, the amounts and types of materials that may be released into the environment and the discharge and disposal of waste materials and, to the extent waste materials are transported and disposed of in onshore facilities, remediation of contaminated sites and the reclamation and abandonmentany releases of wells, sites andthose waste materials from such facilities.  Numerous governmental departmentsagencies 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, the imposition of investigatory, remedial and corrective action obligations or the suspensionincurrence of capital expenditures, the occurrence of restrictions, delays or cessationcancellations in the permitting, or development or expansion of projects and the issuance of orders enjoining some or all of our operations in affected areas.  SomeCertain environmental laws, rulessuch as the federal Oil Pollution Act of 1990, as amended (“OPA”) impose strict joint and regulations relating to protection of the environment may, in certain circumstances, impose strictseveral liability for environmental contamination, such as may arise in the event of an accidental spill on the OCS, rendering a person liable for environmental damagesdamage 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 decommissioning, including 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 federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended, (“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 strict joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies.

In the United States, no comprehensive climate change legislation has been implemented at the federal level, but President Biden is expected to issue nonattainment designationsexecutive orders or pursue legislative or regulatory actions to limit future GHG emissions.  For example, on January 20, 2021, President Biden issued an executive order committing the United States to the Paris Agreement, from which the United States had withdrawn under the Trump Administration.  President Biden has called for additional areasthe federal government to begin formulating the United States’ nationally determined emissions reduction goal under the agreement, which may result in the issuance of GHG limitations in the future.  Additionally, the threat of climate change may result in litigation and financial risks.  Litigation risks are increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the USadverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.  There are also increasing financial risks for fossil fuel producers as well as other companies handling fossil fuels, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the first halffuture to shift some or all of 2018, which areastheir investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainability lending practices and some of them may include regions where we conduct operations.  In addition, the EPA has developed, and continueselect not 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 (“GHG”).  These efforts have included consideration of cap-and-trade programs, carbon taxes, and GHG monitoring and reporting programs.  provide funding for fossil fuel energy companies.

In the absence of federal GHG limitations,

Water Discharges.  The primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”)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 release related damages and economic damages suffered by persons adversely affected by an oil spill.  Although defenses exist to the liability imposed by OPA, they are limited. In addition, in January 2018, the BOEM raised OPA’s damages liability cap to $137.7 million.million; however, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party failed to report a spill or cooperate fully in the cleanup.  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$35.0 million and $150$150.0 million for companies operating on the OCS.  We are currently required to demonstrate, on an annual basis, that we have ready access to $150$150.0 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.an analogous state agency.  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.

Marine Protected Areas and Endangered and Threatened 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 federal Endangered Species Act, as amended (“ESA”).  This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area.  The U.S. Fish and Wildlife Service (USFWS) under former President Trump issued a final rule on January 7, 2021, which notably clarifies that criminal liability under the Migratory Bird Treaty Act (“MBTA”) will apply only to actions “directed at” migratory birds, its nests, or its eggs.  While the rule was scheduled to become effective on February 8, 2021, the USFWS subsequently published notice on February 9, 2021, that it was delaying the effective date of this rule until March 8, 2021, pursuant to the Biden Administration and in conformity with the Congressional Review Act.  Additionally, the USFWS may make determinations on the listing of species as threatened or endangered under the ESA and litigation with respect to the listing or non-listing of certain species may result in more fulsome protections for non-protected or lesser-protected species. 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.  During 2017, we reached an agreement with the various governmental agencies to remove the topside structure on our non-producing platform located in the National Marine Sanctuary and leave the bottom of the platform structure below the water line in place.  This bottom portion of the platform structure will remain due to the density and diversity of marine growth attached to and around the structure.  

Other federal 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 related implementing 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 leases and permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.  Moreover, applicable leasing and permitting programs may be subject to legislative, regulatory or executive actions to delay or suspend the issuance of leases and permits, such as has occurred under the Biden Administration’s DOI order issued on January 20, 2021 with respect to drilling permits, or cancellation of such programs. 

Financial Information

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.

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 has been 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 seasonally 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.

Employees

Human Capital Resources

People are our most valuable asset, and we strive to provide a work environment that attracts and retains the top talent in the industry, reflects our core values and demonstrates our core values to the communities in which we operate.

As of December 31, 2017,2020, our personnel base consisted of 303 of our employees and over 300 individuals who are employees of third parties that provide skilled labor in support of our field operations. This combined workforce conducts our business in Texas, Alabama and the Gulf of Mexico. Our workforce in Texas is primarily composed of our corporate employees, including our executive officers, drilling and production managers, technical engineers and administrative and support staff. Our employees in Alabama and the Gulf of Mexico are primarily composed of skilled labor who conduct our field operations and manage third party personnel used in support of our field operations. We focus on certain measures and objectives when managing our workforce that are material in understanding our business, which are summarized below:

Health and Safety.  Our highest priorities are the safety of all personnel and protection of the environment. To drive a culture of personnel safety in our operations, we employed 298 people.  We are notoperate under a partycomprehensive Safety and Environmental Management System (“SEMS”). Our 2020 total recordable incident rate (“TRIR”) for employees was 0.3, which is far below the industry average for the Gulf of Mexico of 0.5.  Our Health, Safety and Environmental (“HS&E”) group is comprised of a Vice President, and Environmental, Safety and Regulatory Managers and 10 staff personnel. The Department works with field personnel to any collective bargaining agreementscreate and regularly review safety policies and procedures, in an effort to support continuous improvement of our SEMS.

As a company identified by the Federal Government as essential to the critical infrastructure of the United States, we have not experienced any strikescontinuously operated during the COVID-19 pandemic. To provide our personnel with a physically safer work environment and mitigate the risks associated with the transmission of COVID-19, we implement policies requiring mandatory face masks and social distancing in all work environments, conduct daily temperature screening at all locations and COVID-19 testing for field project crews, and limiting headcount to 50% or work stoppages.less in our offices during peak COVID-19 outbreaks in the community.

Recruitment and Compensation.  We consider our relations withpride ourselves on providing an attractive compensation and benefits program that allows our employees to be good.view working at W&T as more than where they work, but a place where they may grow and develop.  Our ability to succeed depends on recruiting and retaining top talent in the industry. We believe employees choose W&T in part due to our professional advancement opportunities, on the job training, engaging culture and competitive compensation and benefits.

As part of our compensation philosophy, we believe we must offer and maintain market competitive total rewards programs in order to attract and retain superior talent. These programs not only include base wages and incentives in support of our pay for performance culture, but also health and retirement benefits. We focus many programs on employee wellness. We believe these solutions help the overall health and wellness of our employees and help us successfully manage healthcare and prescription drug costs for our employee population.

Diversity and Inclusion.  The key to our past and future successes is promoting a workforce culture that embraces integrity, honesty and transparency those we interact, fosters a trusting and respectful work environment that embraces changes and moves us forward in an innovative and positive way.

Additional Information

Our policies and practices support diversity of thought, perspective, sexual orientation, gender, gender identity and expression, race, ethnicity, culture and professional experience. From recent graduates to experienced hires, we seek to attract and develop top talent to continue building a unique blend of cultures, backgrounds, skills, and beliefs that mirrors the world we live in. The tables below present, by category of employee, the gender and ethnicity composition of our employees as of December 31, 2020: 

Website Access to Company Reports

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,5718 Westheimer Road, Suite 300,700, Houston, Texas 7704677057 or by calling (713) 297-8024.  These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549.  The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.  Information on our website is not a part of this Form 10-K.

Item 1A. Risk Factors

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

Risks Relating to Our Industry, Our Business

Market and Our Financial ConditionCompetitive Risks

Crude oil, natural gas and NGL prices can fluctuate widely due to a number of factors that are beyond our control. Depressed oil, natural gas or NGL prices could adversely affectaffects our business, financial condition, cash flow, liquidity or results of operations and could affect our ability to fund future capital expenditures needed to find and replace reserves, meet our 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, ability to produce these commodities economically and future rate of growth.  Crude oil, NGLs and natural gas are commodities and historically have been subject to wide price fluctuations, sometimes in response to minor changes in supply and demand.  These markets for crude oil, NGLs and natural gas have been volatile and will likely continue to be volatile in the future. Although prices increased during 2017 from 2016 and 2015 levels, these past three years of lower prices have substantially decreased our revenues on a per unit basis and reduced the amount of crude oil, NGLs and natural gas that we could produce economically.  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 and NGLs began declining in the second half of 2014 and continued declining until reaching a bottom in the first quarter of 2016, and then slowly rising in 2017.  The average price per barrel of West Texas Intermediate (“WTI”) crude oil was over $90.00 in 2014, approximately $49.00 in 2015, approximately $43.00 per barrel in 2016 and approximately $50.00 per barrel in 2017.  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, approximately $2.50 per MMBtu in 2016 and approximately $3.00 per MMBtu in 2017.  This decrease and volatility in prices has impacted all companies throughout the oil and gas industry.  Although oil prices have increased from the lows of the first quarter of 2016, margins are still below historical levels.  Low prices for crudeHistorically, oil, NGLs and natural gas prices could materiallyhave been volatile and adversely affect our future business, financial condition, results of operations, liquidity, abilitysubject to finance planned capital expenditures, abilitywide price fluctuations in response 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,domestic and to meet our other financial obligations.

The borrowing base under our Credit Agreement may be reduced or may not be extended by our lenders.

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.  During 2017, there were noglobal changes in supply and demand, economic and legal forces, events and uncertainties, and numerous other factors beyond our control, including:  

These factors and the borrowing base undervolatility of the Credit Agreement from year-end 2016, but during 2016, the borrowing base was reduced from $350 millionenergy markets, which we expect to $150 million.  The borrowing base was lowered primarily duecontinue, make it extremely difficult to declines inpredict future commodity prices and a decrease in proved reserves.  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 the 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.  If crude oil, NGLs and natural gas prices fall back to the levels experienced in 2016, this would 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.

The Credit Agreement matures on November 8, 2018 and our lenders have indicated that they are unwilling to extend the Credit Agreement given the current maturities of our other debt instruments, including the potential maturity acceleration of two of our debt instruments to February 28, 2019.  We may not be able to execute our plans to address this issue, which would cause us to operate without a revolving bank credit facility.

We may be unable to provide the financial assurances if the BOEM submits future demands 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 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 the 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.  NTL #2016-N01 became effective in September 2016, but the BOEM has since extended indefinitely the start date for implementation.

In December 2016, we received the December 2016 Order totaling approximately $29.5 million for our sole liability properties.  However, following the BOEM’s action in January 2017 to extend the implementation date of NTL #2016-N01 for a period of six months, the BOEM elected to include sole liability properties as being covered under the extension and thus issued us a letter on February 21, 2017, rescinding the December 2016 Order, while the BOEM reviewed its financial assurance program.  In June 2017, the BOEM further extended the start date for the implementation of NTL #2016-N01 indefinitely beyond June 30, 2017.  This extension currently remains in effect; however, the BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning sole liabilities.

  As of the filing date of this Form 10-K, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders or financial assurance obligations.  Following completion of its review, the BOEM may elect to retain NTL #2016-N01 in its current form or may make revisions thereto and, thus, until the review is completed and the BOEM determines what additional financial assurance may be required by us, we cannot provide assurance that such financial assurance coverage can be obtained.  Moreover, the BOEM could in the future make other demands for additional financial assurances covering our obligations under sole liability properties and/or our non-sole liability properties.  The BOEM may reject our proposals and make demands that exceed the Company’s capabilities.  

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

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

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

If we are required to provide collateral, our liquidity position will be negatively impacted and may require us to seek alternative financing.  To the extent we are unable to secure adequate financing; we may be forced to reduce our capital expenditures in the current year and/or future years.  In addition, a reduction in our liquidity may impair our ability to comply with the financial and other restrictive covenants in our indebtedness.  Moreover, if we default on our Credit Agreement, then we would need a waiver or amendment from our bank lenders to prevent the acceleration of the outstanding debt under our Credit Agreement.  There is no assurance that the bank lenders will waive or amend the Credit Agreement.  Realization of any of these factors could have a material adverse effect on our financial condition, results of operations and cash flows.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.  

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, 2017, we had $889.8 million principal amount of indebtedness outstanding, which consists of $189.8 million principal amount of unsecured indebtedness and $700.0 million principal amount of secured indebtedness.  Our current availability on our revolving bank credit facility is the full borrowing base of $150.0 million.  We did not incur any borrowings on our revolving bank credit facility during 2017.  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.certainty.

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 debt instruments 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, 2017, we had $700.0 million principal amount of secured indebtedness outstanding and $189.8 million principal amount of unsecured indebtedness outstanding (which does not include amounts recorded in the carrying value of certain debt instruments 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 face could intensify.  As of December 31, 2017, the various debt agreements allowed for approximately $200 million of second lien debt and approximately $400 million of third lien debt.  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.

A significant amount of our indebtedness will accelerate if we are not able to extend, renew, refund, defease, discharge, replace or refinance our Unsecured Senior Notes by certain dates under various debt agreements, which would adversely impact our liquidity.  

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.  The Unsecured Senior Notes mature on June 15, 2019 with a principal balance of $189.8 million.  Assuming the PIK option is fully utilized for the Third Lien PIK Toggle Notes, the principal balance would be approximately $164.5 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 $239.5 million may become due on February 28, 2019.

In addition, the lenders under our Credit Agreement, which matures on November 8, 2018, have indicated that they are unwilling to extend the Credit Agreement, and other lenders may be unwilling to extend a replacement revolving credit facility, unless and until the potential maturity acceleration of our Third Lien PIK Toggle Notes and the 1.5 Lien Term Loan to February 28, 2019 is addressed.  Each of our Second Lien Term Loan and Second Lien PIK Toggle Notes require us to offer to repay or repurchase the Second Lien Term Loan and Second Lien PIK Toggle Notes, as applicable, at par plus accrued and unpaid interest if, by May 16, 2019, the aggregate outstanding principal amount of Unsecured Senior Notes that have not been repurchased, redeemed, discharged, defeased or called for redemption exceeds $50.0 million.  

We may not be able to execute on various financing alternatives under consideration to address these maturity issues, which include having sufficient available cash or net proceeds from replacement financings to redeem the Unsecured Senior Notes, which are currently callable at par, and the 1.5 Lien Term Loan, which is callable after September 7, 2018 at 102.75% of par.  In addition, certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized.  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 February 28, 2019.  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 be on less favorable terms or on terms that are not acceptable to us.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.  

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 equity and debt capital markets.  If those markets are unavailable, 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, 2017, we had $700.0 million principal amount of secured indebtedness outstanding, (which does not include amounts recorded in the carrying value of certain debt instruments for PIK and cash interest payments).  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 $149.7 million as of December 31, 2017, 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 downreduce the estimated volumes and future value associated with our total proved reserves or record impairments to 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

Lower 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, NGLs and natural gas prices declined in 2015, we incurred impairment charges in each quarter in 2015 totaling $987.2 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 $279.1 million.  We did not incur any such write-downs during 2017.  If prices fall below 2016 levels, this may cause write-downs during 2018 or in future periods.  In addition, lower crude oil, NGLs and natural gas prices may reduce our estimates of the proved reserve volumes that may be economically recovered, which would reduce the total volumes and future 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 resultsUnder the full cost method 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-Kaccounting 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 that 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 16% of our total proved reserves as of December 31, 2017 and require additional 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 into proved producing reserves.  Although we are the operator for all the fields containing our PUDs as of December 31, 2017, in the past, we were not the operator for a portion of our PUDs, which if this were to occur in the future, may 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 reserves in many other producing regions of the United States.  Our independent petroleum consultant estimates that 50% 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 because of our relatively high leverage and we believe our access to capital markets remains limited at this time.  Our capital expenditures in 2017 were below historical levels and we continue to have a low capital expenditure budget for 2018 in order to conserve capital and target projects with a high 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 if commodity prices decline) 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 2017 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 rulemakings could further restrict offshore air emissions.

In May 2017, the Department of the Interior Secretary Ryan Zinke issued Order 3350 (“Order 3350”) directing the BSEE and the BOEM to reconsider a number of regulatory initiatives governing oil and natural gas exploration in offshore federal waters related to safety, air quality control and performance-related activities.  Examples of such regulatory initiatives being reconsidered include NTL #2016-N01 and the rules relating to blow-out preventers and well control.  Following completion of their reviews, these agencies are to provide recommendations on whether such regulatory initiatives should continue or be implemented.  Moreover, Order 3350 directed the BOEM to immediately cease all activities to promulgate the April 2016 proposed rule relating to offshore air quality control.  One consequence of this review is that in December 2017, the BSEE published proposed revisions to its regulations regarding offshore drilling safety equipment, which proposal includes the removal of the requirement for offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g., subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extreme conditions.  The December 2017 proposed rule has not been finalized and there remains substantial uncertainty as to the scope and extent of any revisions to existing oil and gas safety and performance-related regulations and other regulatory initiatives that ultimately will be adopted byproducing activities, a ceiling test is performed at the BSEE and the BOEM pursuantend of each quarter to those agencies’ review process.

To the extent that the BOEM and the BSEE do not reduce the stringency of existing oil and gas safety and performance-related regulations and other regulatory initiatives, the regulatory requirements imposed by such existing or future, more stringent regulations or other regulatory initiatives 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.  Additionally,determine if left unchanged, the existing, or future, more stringent oil and gas safety and performance-related regulations and other regulatory initiatives imposed by the BOEM and BSEE could 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.  Also, 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.  We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limitshave been impaired. Capitalized costs of coverage for higher valuedoil and gas properties and wells.  The current policy limits for well control range from $30.0 millionare generally limited to $500.0 million dependingthe present value of future net revenues of proved reserves based on the risk profile and contractual requirements.  With respectaverage price of the 12-month period prior to coveragethe ending date of each quarterly assessment using the unweighted arithmetic average of the first-day-of-the-month price for named windstorms, we have a $150.0 million aggregate limit covering alleach month within such period.  Impairments of our oil and gas properties subjectare more likely to a retention (deductible)occur during prolonged periods of $30.0 million.  Included within the $150.0 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention.  

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 conditiondepressed crude oil, NGL and operations.  Our insurance does not protect us against all operational risks.  We do not carry business interruption insurance.  In May and June 2017, we entered into our insurance policies covering well control and hurricane damage (described above) and for general liability and pollution.  These policies are effective for one year from their respective execution date.  These policies reduce, but in no way totally mitigate our risknatural gas pricing, as we are exposed to amounts for retention and co-insurance, limits on coverage and events that are not insured.  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 lawsexperienced 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,2020. While we have not obtained insurance as we believerecorded an impairment of our oil and gas properties during the cost of available insurance is excessive relativeyear-ended December 31, 2020, any further decreases in commodity pricing could cause an impairment, which would result in a non-cash charge 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 becomes limited from time to time and the cost of such coverage becomes both more costly and more volatile.  In the past, we have been able to renew our policies each annual period, but our coverage has varied depending on the premiums charged, our assessment of the risks and our ability to absorb a portion of the risks.  The insurance market may further change dramatically in the future due to hurricane damage, major oil spills or other events.earnings.   

 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.

Commodity derivative positions may limit our potential gains.

In order to manage our exposure to price risk in the marketing of our oil and natural gas, and as required under the Sixth Amended and Restated Credit Agreement (the "Credit Agreement"), we periodically enter into oil and natural gas price commodity derivative positions with respect to a portion of our expected production.  During the first quarter of 2017, we entered into commodity derivative contracts, which expired on or before December 31, 2017.  As of the filing date ofSee Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K we did not have any open commodityfor a full description the Credit Agreement.  See Financial Statements and Supplementary Data– Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on our derivative positions.contracts and transactions.  We may enter into more derivative contracts in the future.  While these commodity derivative positions are intended to reduce the effects of volatile crude oil and natural gas prices,price volatility, 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 forto acquire 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 competeFinally, companies with other companies in our industry for such properties through a private bidding process, direct negotiations or some combination thereof.  Our competitorslarger financial resources may have significantly more capital resources and less expensive sourcesa significant advantage in terms of capital.  In addition, they may be able to generate acceptable rates of return from marginal prospects due to their lower costs of capital.meeting any potential new bonding requirements.  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

Market conditions or operational impediments may hinder our access to oil and natural gas companies, commodity prices, general economicmarkets or delay our production. The marketability of our production depends mostly upon the availability, proximity, and capacity of oil and natural gas gathering systems, pipelines and processing facilities, which in some cases are owned by third parties.

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 some cases are owned and operated by third parties.

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.  These pipelines may become unavailable for a number of reasons, including testing, maintenance, capacity constraints, accidents, government regulation, weather-related events or other factors we cannot controlthird-party actions. If any of these third-party pipelines become partially or influence.  Additional requirementsfully unavailable to transport crude oil and limitations recently imposed on us andnatural gas, or if the gas quality specification for the natural gas pipelines changes so as to restrict our ability to financetransport natural gas on those pipelines, our revenues could be adversely affected. 

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 acquisitions may put us at a competitive disadvantageoil 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, 2020, three fields, accounting for acquiring properties.  These risksapproximately 0.1 MMBoe (or 1%) of our 2020 production, are described above intied back to separate, third-party owned platforms.  There can be no assurance that the risk factor entitled: owners of such platforms will continue to process our oil and natural gas production. 

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, gathering system capacity or processing facilities.  If that were to occur, then we would be unable to provide the financial assurances if the BOEM submits future demandsrealize revenue from those wells until arrangements were made to coverprocess or deliver our decommissioning obligationsproduction to market.  We have, in the amountspast, been required to shut in wells when hurricanes have caused or threatened damage to pipelines, gathering stations, and underproduction facilities. In addition, certain third-party pipelines have submitted requests in the time periods required bypast to increase the BOEM.  If extensions and modificationsfees they charge us to the BOEM’s demands are needed and cannot be obtained, the BOEMuse these pipelines.  These increased fees, if approved, could elect to take actions that would materially adversely impact our operationsrevenues or increase our operating costs, either of which would adversely impact our operating profits, cash flows and reserves.

Operating Risks

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. We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties including commencing proceedingswhich include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells.  Our insurance does not protect us against all operational risks.  We do not carry business interruption insurance.  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 suspenddrill our operationswells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees.

Currently OPA requires owners and operators of offshore oil production facilities to have ready access to $150.0 million that can be used to cover costs that could be incurred in responding to an oil spill 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. 

For some risks, we have not obtained insurance as we believe the cost of available insurance is excessive relative to the risks presented. We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or cancelretentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. The occurrence of a significant event not fully insured or indemnified against losses could have a material adverse effect on our federal offshore leases.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 Claimsand Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on insurance coverage.

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.water, sophisticated sea floor production handling equipment, expensive state-of-the-art platforms and infrastructure investments.  Deepwater wells have greater mechanical risks because the wellhead equipment is installed on the sea floor.  DeepwaterIn addition, due to the significant time requirements involved with exploration and development costs can be significantly higher than development costsactivities, particularly for wells drilled onin the conventional shelf because deepwater drilling requires larger installation equipment, sophisticated sea flooror wells not located near existing infrastructure, actual oil and natural gas 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.from new wells may not occur, if at all, for a considerable period of time following the commencement of any particular project. Accordingly, we cannot assure youprovide assurance that our oil and natural gas exploration activities in the deep shelf, the deepwater and elsewhere will be commercially successful.

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.  In that case, 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.  

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

The exploration, development and production of oil and gas properties involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collisions and adverse weather and sea conditions, including the effects of hurricanes. 

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. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production, repairs to resume operations and loss of reserves. Any of these industry operating risks could have a material adverse effect on our business, results of operations and financial condition.

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 severe weather, including tropical storms and hurricanes; delays or decreases in production, the availability of equipment, facilities or services; changes in the status of pipelines that we depend on for transportation of our production to the marketplace; delays or decreases in the availability of capacity to transport, gather or process production; and changes in the regulatory environment.

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. 

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 becomes limited from time to time and the cost of such coverage becomes both more costly and more volatile.  In the past, we have been able to renew our policies each annual period, but our coverage has varied depending on the premiums charged, our assessment of the risks and our ability to absorb a portion of the risks.  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.

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, 2020. 

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 standardized measure or 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 rates 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, which 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. 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.

The COVID-19 pandemic has affected, and may continue to materially adversely affect, our industry, business, financial condition or results of operations.

The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the oil and gas industry. The COVID-19 outbreak and the responsive actions to limit the spread of the virus have significantly reduced global economic activity, resulting in a decline in the demand for oil, natural gas, and other commodities. These economic consequences have been a primary cause of the significant supply-and-demand imbalance for oil. The current supply-and-demand imbalance and significantly lower oil pricing may continue to affect us, constraining our ability to store and move production to downstream markets, or affecting future decisions to delay or curtail development activity or temporarily shut-in production which could further reduce cash flow.

The extent of the impact of the COVID-19 pandemic and any other future pandemic on our business will depend on the nature, spread and duration of the disease, the responsive actions to contain its spread or address its effects, its effect on the demand for oil and natural gas, the timing and severity of the related consequences on commodity prices and the economy more generally, including any recession resulting from the pandemic, among other things.  Any extended period of depressed commodity prices or general economic disruption as a result of the pandemic would adversely affect our business, financial conditions and results of operations.  In addition, the COVID-19 pandemic has heightened the other risks and uncertainties described in this report.

Our operations could be adversely impacted by security breaches, including cybersecurity breaches, which could affect the systems, processes and data needed to run 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, interference with treasury function, theft or acts of vandalism or terrorism.  A breach could result in an interruption in our operations, malfunction of our platform control devices, disabling of our communication links, 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.

The loss of members of our senior management could adversely affect us.

To a large extent, we depend on the services of our senior management.  The loss of the services of any of our senior management 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.

Capital Risks

We have a significant amount of indebtedness and limited borrowing capacity under our current Credit Agreement, which may be reduced by our lenders.  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, 2020, we had $632.5 million in principal of indebtedness outstanding and $4.4 million of letters of credit obligations outstanding, substantially all of which is secured. During 2020, we incurred $61.5 million in interest expense.  Our leverage and debt service obligations could:

Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations. If new debt is added to our current debt levels, the related risks that we face could intensify. Additionally, availability of borrowings and letters of credit under our Credit Agreement is determined by establishment of a borrowing base, which is periodically redetermined in lenders’ sole discretion based on our lenders’ review of crude oil, NGLs and natural gas prices, our proved reserves and other criteria. Lower crude oil, NGLs and natural gas prices in the future would also adversely affect our cash flow and could result in reductions in our borrowing base and sources of alternate credit and affect our ability to satisfy the covenants and ratios required by the Credit Agreement and Indenture.

We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt or otherwise meet our future obligations. In such scenarios, we may be required to refinance all or part of our existing debt, sell assets, reduce capital expenditures, obtain new financing or issue equity. However, we may not be able to accomplish any of these transactions on terms acceptable to us or such actions may not yield sufficient capital to meet our obligations.  Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our debt agreements contain restrictions that limit our abilities to incur certain additional debt or liens or engage in other transactions, which could limit growth and our ability to respond to changing conditions.

The Indenture and Credit Agreement 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 Credit Agreement 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 outstanding notes.

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.

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.

All of our existing indebtedness under our Credit Agreement and our outstanding Second Lien Senior Notes is secured by liens on substantially all of our oil, natural gas and NGL properties. In addition, we have certain rights to issue or incur additional or new secured debt, including up to $105.6 million as of January 6, 2021, available for borrowing under our Credit Agreement following the most recent redetermination, 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. 

With respect to some of the collateral securing our 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.  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. 

We may be required to post cash collateral pursuant to our agreements with sureties under our existing or future 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 future bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the surety’s sole discretion.  Additional collateral would likely be in the form of cash or letters of credit.  We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for future bonds.

If we are required to provide additional collateral, our liquidity position will be negatively impacted, and we may be required 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 or future years, may be unable to execute our ARO plan or may be unable to comply with our existing debt instruments.

Legal and Regulatory Risks

The recent election of President Biden and changes in U.S. Congress may result in significant legislative and regulatory changes that could adversely affect our results of operations, and our ability to implement our business strategy.

Recently elected President Biden has indicated that his administration will pursue regulatory initiatives, executive actions and legislation in support of his regulatory and political agenda, which includes the reduction in dependence on, and use of, fossil fuels and curtailment of hydraulic fracturing on federal lands in response to climate change and other environmental risks. Our operations in the Gulf of Mexico require permits from federal and state governmental agencies in order to perform drilling and completion activities and conduct other regulated activities. Under certain circumstances, U.S. federal agencies may refuse to approve new leases for hydrocarbon exploration and development on federal lands and waters and may refuse to grant or delay approvals required for development of existing leases on such lands and waters. See Part I, Item 1. “Business – Compliance with Environmental Regulations” for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry that are being pursued under the Biden Administration. To the extent that our operations in federal waters are restricted, delayed for varying lengths of time or cancelled, such developments could have a material adverse effect on our results of operations, our ability to replace reserves and the ability to implement our business strategy.

We may be unable to provide the financial assurancesin the amounts and under the time periods required by the BOEM if the BOEM submits future demands to cover our decommissioning obligations.  If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, 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 and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.  As of the filing date of this Form 10-K, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders, requests or financial assurance obligations.  The BOEM under the Obama Administration had sought to implement more stringent and costly standards under the existing federal financial assurance requirements through issuance and implementation of NTL #2016-N01, but former President Trump’s Administration first paused, and then in 2020 rescinded, the implementation of this NTL while the BOEM issued a proposed rulemaking in October 2020 to amend its financial assurance program. The BOEM under the Biden Administration may in the future reconsider offshore financial assurance requirements, including the rescinded NTL #2016-N01 and the October 2020 proposed rule, and adopt and implement more stringent requirements.  Moreover, the BOEM could make demands for additional financial assurances covering our obligations under our properties, which could exceed the Company’s capabilities to provide.  If we fail to comply with such future orders, the BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.

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

SEC rules require that, subject to limited exceptions, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of initial booking. This requirement may limit our ability to book additional PUD reserves as we pursue our drilling program. Moreover, we may be required to write down our PUD reserves if we do not drill those wells within the required five-year timeframe.

Additional deepwater drilling laws, regulations and other restrictions, delays and other offshore-related developments in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

President Biden and one or more of agencies under his administration has issued orders temporarily suspending leasing or permitting of oil and natural gas activities on federal lands and waters, including the OCS, and his administration is expected to pursue additional orders, legislation and regulatory initiatives regarding deep water leasing, permitting or drilling that could result in more stringent or costly restrictions, delays or cancellations to our operations as well as those of similarly situated offshore energy companies on the OCS. The BSEE and the BOEM have over the past decade, primarily under the Obama Administration, imposed more stringent permitting procedures and regulatory safety and performance requirements with respect to new wells drilled in federal deepwater. While, in recent years under the Trump Administration, there have been actions by BSEE or BOEM seeking to mitigate or delay certain of those more rigorous standards, we expect that the Biden Administration may reconsider rules and regulatory initiatives implemented under the Trump Administration. Compliance with any 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 under the Biden Administration are expected to continue to evaluate aspects of safety and operational performance in the United States Gulf of Mexico that could result in new, more restrictive requirements. For example, under the Trump Administration, BSEE reviewed and delayed or revised certain offshore regulations implemented during the Obama Administration with respect to the imposition of rigorous standards relating to well control. In light of the statements made by President Biden, there exists a significant risk that these Obama-era regulations, or additional, more stringent regulations impacting our business, properties and results of operations could be reimplemented or adopted during the Biden Administration.

These regulatory actions, or any new rules, regulations, or legal initiatives or controls that impose increased costs or more stringent operational standards could delay or disrupt our operations, result in increased supplemental bonding and costs and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities or result in the suspension or cancellation of leases.  Also, if material spill incidents were to occur in the future, the United States could elect to issue directives to temporarily cease drilling activities and, in any event, 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.  See Part I, Item 1. “Business – Compliance with Environmental Regulations” for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry that are being pursued under the Biden Administration.

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, and inactive or damaged facilities and equipment, collectively referred to as “idle iron,” and to restore the land or seabed at the end of oil and natural gas production operations.  TheseIn December 2018, BSEE issued an updated NTL reaffirming the obligations of offshore operators to timely decommission idle iron by means of abandonment and removal.  Pursuant to the idle iron NTL requirements, in September 2019, BSEE issued us letters, directing us to plug and abandon certain wells that the agency identified as no longer capable of production in paying quantities by specified timelines, with the earliest deadline being December 31, 2020.   In response, we are currently evaluating the list of wells proposed as idle iron by BSEE and currently anticipate that those wells determined to be idle iron will be decommissioned by the specified timelines or at times as otherwise determined by BSEE following further discussions with the agency.  While we have established AROs for well decommissioning, additional AROs, significant in amount, may be necessary to conduct plugging and abandonment of the wells designated by BSEE as idle iron, but we do not expect the costs to plug and abandon these wells will have a material effect on our financial condition, results of operations or cash flows.  Nevertheless, these decommissioning activities 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.depths, and there exists the possibility that increased liabilities beyond what we established as AROs may arise and the pace for completing these activities could be adversely affected by idle iron decommissioning activities being pursued by other offshore oil and gas lessees that may also have received similar BSEE directives, which could restrict the availability of equipment and experienced workforce necessary to accomplish this work. 

Moreover, BSEE under the Biden Administration could also reconsider its 2018 NTL or existing idle iron-related regulations and establish new, more stringent decommissioning requirements on an expedited basis.  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.

The additional requirements under the BOEM’s formerly issued NTL #2016-N01, if everit were re-issued and fully implemented, or in the event BOEM under the Biden Administration were to otherwise issue new, more stringent financial assurance guidance or requirements, would increase our operating costs and reduce the availability of surety bonds due to the increased demands for such bonds in a low-price commodity environment.  While the current implementation timeline has been extended indefinitely, except in certain circumstances where there was a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, this timeline could change at the BOEM’s discretion and the BOEM may re-issue sole liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  Under NTL #2016-N01, the BOEM has given broader interpretation authority to the BOEM’s district personnel, which increases the difficulty in complying with this NTL should it be fully implemented.  In addition, increased demand for salvage contractors and equipment could result in increased costs for decommissioning activities, including 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 natural gas interests with other companies, we are obligated to pay our share of operating, capital and decommissioning 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 obligationsimposes strict joint and several liability under the OCSLA on the various lessees of lessees undera federal oil and gas leases,lease for lease obligations, including obligations for decommissioning costs, is generally joint and several among the various co-owners of the lease,activities, which means that any single ownerco-lessee may be liable to the U.S. Government for the full amount of all of the multiple lessees’ obligations under the lease.  In certain circumstances, we also could be liable for accrued decommissioning liabilities on federal oil and gas leases that we previously owned and assigned to an unrelated third party should the assignee to whom we assigned the leases or any future assignee of those leases is bankrupt or unable to payperform its decommissioning costs.obligations (including payment of costs incurred by unrelated parties in decommissioning such lease facilities).  For example, we have in the past received a demand for payment of suchdecommissioning 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.  In that case, 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 1.7 MMBoe was deferred during 2017 due to Hurricane Nate, pipeline issues and other events.  A similar amount was deferred during 2016 due to events outside of our control.  

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 has historically been 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, 2017.  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 from Tropical Storm Karen and in 2017 from Hurricane Nate.

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, 2017, 10 fields, accounting for approximately 0.8 MMBoe (or 6%) of our 2017 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.  These pipelines may become unavailable for a number of reasons, including testing, maintenance, capacity constraints, accidents, government regulation, weather-related events or other third-party actions.  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 2017, various pipelines were shut down at various times causing production deferral of approximately 0.4 MMBoe.  

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 increase our 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:

Under these laws and regulations, we could be liable for:

Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. Regulated matters include lease permit restrictions; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can discharge materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well decommissioning costs; the spacing of wells; operational reporting; reporting of natural gas sales for resale; and taxation.  Under these laws and regulations, we could be liable for personal injuries; property and natural resource damages; well site reclamation costs; and governmental sanctions, such as fines and penalties.

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 and regulations as well as legal requirements applicable to MPAs and endangered species laws and regulations.threatened species.

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: