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Primarily related to extensions and discoveries of 1.3 MMBoe at our Viosca Knoll 823 (Virgo) field and 0.7 MMBoe at our Ewing Bank 910 field. Primarily related to the discovery at East Cameron 338 field. Defined below Includes both open and closed contracts. Primarily related to upward revisions at our Mahogany field and our Ship Shoal 028 field. Additionally, increases of 2.3 MMBoe were due to price revisions. Includes net additions from capitalized ARO of of $18.0 million, $37.5 million, and $20.3 million during 2020, 2019, and 2018, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. Includes geological and geophysical costs charged to expense of of $4.5 million, $5.7 million, and $5.4 million during 2020, 2019, and 2018, respectively. Primarily related to extensions and discoveries of 0.9 MMBoe at our Mississippi Canyon 800 (Gladden) field. Primarily related to the Mobile Bay Properties and Magnolia acquisitions. During 2020, we recorded a derivative (gain) loss of $(61.9) million, 15.4 million, 11.2 million, and $11.5 million in the first, second, third and fourth quarters, respectively. During 2020, we recorded gain on debt transactions of $47.5 million. During 2020, we recorded income tax expense (benefit) of $6.5 million, ($8.7) million, ($21.1) million and ($6.9) million in the first, second, third and fourth quarters, respectively. During 2019, we recorded a derivative loss (gain) of $48.9 million, ($1.8) million, ($5.9) million, and $18.7 million in the first, second, third and fourth quarters, respectively. During 2019, we recorded income tax expense (benefit) of $0.2 million, ($11.7) million, ($55.5) million and ($8.2) million in the first, second, third and fourth quarters, respectively. We believe that we will be able to develop all but 2.3 MMBoe (approximately 19%) of the total of 12.2 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2020, within five years from the date such reserves were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field ("Matterhorn") and Viosca Knoll 823 ("Virgo") deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one each at Matterhorn and Virgo, will be delayed until an existing well is depleted and available to sidetrack. We also plan to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of existing well. Based on the latest reserve report, these PUD locations are expected to be developed in 2022 and 2024. The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. Increases primarily related to upward revisions to our Ship Shoal 028 field and our Main Pass 108 field. Decreases of 10.0 MMBoe were due to price revisions for all proved reserves, which include estimated price revisions of the purchase of minerals in place from the date of purchase to December 31, 2019. Primarily related to the Mobile Bay Properties and Mahogany working interest acquisitions. Primarily related to our Ship Shoal 028 field and our Green Canyon 859 field (Heidelberg). During 2020 and 2019, only common shares were used to settle vested RSUs and Restricted Shares. During 2018, cash was used to settle vested RSUs related to the retirement of executive officers and shares of common stock were used to settle all other vested RSUs and to settle Restricted Shares. Includes seismic costs of $0.3 million, $7.8 million, and $1.5 million incurred during 2020, 2019, and 2018, respectively. Primarily related to conveyance of interest in properties related to the JV Drilling Program. Revisions in 2020 and 2019 were due to changes in scope, weather impact, revisions to actual expenses versus estimates and revisions related to non-operated properties. Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet. The majority of such costs were recorded within Oil and natural gas properties, net, on the Consolidated Balance Sheet. Decreases of 27.7 MMBoe were due to price revisions for all proved reserves. 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Form 10-K




For the fiscal year ended December 31, 2020






For the transition period from                      to                     

Commission File Number 1-32414




(Exact name of registrant as specified in its charter)






(State or other jurisdiction of incorporation or organization)


(I.R.S. Employer Identification Number)


5718 Westheimer Road, Suite 700 Houston, Texas



(Address of principal executive offices)


(Zip Code)


(713) 626-8525

(Registrant’s telephone number, including area code)




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






Title of each class


Trading Symbol(s)


Name of each exchange on which registered

Common Stock, par value $0.00001




New York Stock Exchange


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


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 every interactive data file required to be submitted 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 such files).    Yes  ☑    No  ☐


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.


Large accelerated filer



Accelerated filer


Non-accelerated filer




Smaller reporting company




Emerging growth company



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 $213,418,732 based on the closing sale price of $2.28 per share as reported by the New York Stock Exchange on June 30, 2020.


The number of shares of the registrant’s common stock outstanding on February 28, 2021 was 142,304,770.




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.











Glossary of Oil and Gas Terms



Item 1.




Item 1A.

Risk Factors



Item 1B.

Unresolved Staff Comments



Item 2.




Item 3.

Legal Proceedings




Executive Officers of the Registrant



Item 4.

Mine Safety Disclosures







Item 5.

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



Item 6.

Selected Financial Data



Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations



Item 7A.

Quantitative and Qualitative Disclosures About Market Risk



Item 8.

Financial Statements and Supplementary Data



Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure



Item 9A.

Controls and Procedures



Item 9B.

Other Information







Item 10.

Directors, Executive Officers and Corporate Governance



Item 11.

Executive Compensation



Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters



Item 13.

Certain Relationships and Related Transactions, and Director Independence



Item 14.

Principal Accountant Fees and Services







Item 15.

Exhibits and Financial Statement Schedules












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 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 Form 10-K to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.







The 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.







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.


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.  We currently hold working interests in 43 offshore producing fields in federal and state waters.  Our acreage, well, production and reserves information is described in more detail under Part I Item 2, Properties, in this Form 10-K.  Our working interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiary, W&T Energy VI, LLC, a Delaware limited liability 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.  


We have developed significant technical expertise in finding and developing properties in the Gulf of Mexico with production rates which provide the best opportunity to achieve a rapid return on our invested capital. We have leveraged our experience in the conventional shelf to develop higher impact capital projects in the Gulf of Mexico in both the deepwater and the deep 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. 


Business Strategy


Our goal is to pursue high rate of return projects and develop oil and natural gas 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:



Exploiting existing and acquired properties to add additional reserves and production;



Exploring for reserves on our extensive acreage holdings and in other areas of the Gulf of Mexico;



Acquiring reserves with substantial upside potential and additional leasehold acreage complementary to our existing acreage position at attractive prices; and



Continuing to manage our balance sheet in a prudent manner and continuing our track record of financial flexibility in any commodity price environment.


Our focus is on making profitable investments while operating within cash flow, maintaining sufficient liquidity, cost reductions and fulfilling our contractual, 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 plans. 


Market Trends


In managing our business, we are focused on optimizing production and increasing 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 commodities we produce (crude oil, natural gas and the natural gas liquids ("NGLs") extracted from natural gas).  In addition, the prices of goods and services used in our business can vary and impact our cash flows.




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 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 2020, average realized commodity prices decreased from those we experienced during 2019.  Our margins in 2020 decreased from 2019 primarily due to lower average realized commodity prices, partially offset by lower operating expenses as a result of our cost-cutting efforts in 2020.  We measure margins using net income (loss) before net interest expense; income tax (benefit) expense; depreciation, depletion, amortization and accretion; unrealized commodity derivative gain or loss; amortization of derivative premiums; bad debt reserve; gain on debt transaction; litigation; and other (“Adjusted EBITDA”) as a percent of revenue, which is a not a financial measurement under generally accepted accounting principles (“GAAP”).


Our production increased 3.8 % in 2020 from the prior year. Our proved reserves decreased by 13.0 million barrels of oil equivalent ("MMBoe") in 2020, primarily due to the significant decline in commodity prices in 2020 as compared to 2019. MMBoe was computed on an equivalency ratio as described above.  During 2020, we drilled one well which we expect to complete in 2021.


We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2021 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.




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 2020, approximately 39% of our revenues were received from BP Products North America, 13% to Williams Field Services and 10% to Mercuria Energy America Inc. Trading (US) Co., with no other customer comprising greater than 10% of our 2020 revenues. Given the commoditized nature of the products we produce and market and the location of our production in the Gulf of Mexico, we believe the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas, 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 a fixed volumes of physical products to customers. 





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 non-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 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 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 $1.0 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 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 BSEE also regulates 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 and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.  In 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, it 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 the authority to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning 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. Under applicable BSEE regulations, lessees operating on the OCS and conducting decommissioning activities are required to submit summaries of actual expenditures for decommissioning of subject wells, platforms, and other facilities. The BSEE has reported that it uses 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 ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant utilized during that period.


Regulation and transportation of natural gas.  Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The FERC has undertaken various initiatives to increase competition within the natural gas industry.  As a result of initiatives like FERC Order No. 636, issued in 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 effect 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, which 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 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtu”) during a calendar year must annually report such sales and purchases to the FERC to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.  It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.  These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation.





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


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


Oil and NGLs transportation rates.  Our sales of 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 production 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 any releases of those waste materials from such facilities.  Numerous governmental agencies 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 criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, or development or expansion of projects and the issuance of orders enjoining some or all of our operations in affected areas.  Certain environmental laws, such as the federal Oil Pollution Act of 1990, as amended (“OPA”) impose strict joint and several liability for environmental contamination, such as may arise in the event of an accidental spill on the OCS, rendering a person liable for environmental damage and cleanup costs without regard to negligence or fault on the part of such person. 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.


The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”), regulates the generation, transportation, storage, treatment and disposal of non-hazardous and hazardous wastes and can require cleanup of hazardous waste disposal sites.  RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste”, and the disposal of such oil and natural gas exploration, development and production wastes is regulated under less onerous non-hazardous waste requirements, usually under state law.  


Standards have been developed under RCRA and/or state laws for worker protection from exposure to Naturally Occurring Radioactive Materials (“NORM”); treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated piping valves, containers and tanks.  Historically, we have not incurred any material expenditures in connection with our compliance with the existing RCRA and applicable state laws related to NORM waste.
Air Emissions and Climate Change.  Air emissions from our operations are subject to the federal Clean Air Act, as amended (“CAA”), and comparable state and local requirements.  We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.  For example, in 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality Standard for ground level ozone from 75 to 70 parts per billion.  Since that time, the EPA issued area designations with respect to ground-level ozone and, on December 31, 2020, published notice of a final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups have filed litigation over this December 2020 final action, and the NAAQS may be subject to revision under the Biden Administration.


In the United States, no comprehensive climate change legislation has been implemented at the federal level, but President Biden is expected to issue executive 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 the 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 adverse 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 future to shift some or all of their 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 elect not to provide funding for fossil fuel energy companies.





From a regulatory perspective, the EPA has determined that GHG emissions present a danger to public health and the environment, and it has adopted regulations that, among other things, restrict emissions of GHG under existing provisions of the CAA and may require the installation of control technologies to limit emissions of GHG.  For example, in 2016, the EPA under the Obama administration published a final rule establishing new source performance standards (“NSPS”) that require new, modified, or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile organic compound emissions.  The 2016 rule applies to any new or significantly modified facilities that we construct in the future that would otherwise emit large volumes of GHG together with other criteria pollutants.  The 2016 new source performance standards regulate GHGs through limitations on emissions of methane.  However, the EPA under the Trump Administration has undertaken several measures, including publishing in September 2020 final rule policy and technical amendments to the NSPS, for stationary sources of air emissions. The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and volatile organic compound requirements for the remaining sources that were established by former President Obama's Administration, whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules, recordkeeping and reporting requirements, and more. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA's September 2020 final rules, and on January 20, 2021, President Biden issued an executive order, that among other things, directed EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding those amendments by no later than September 2021.  A reconsideration of the September 2020 policy amendments is expected to follow. The January 20, 2021 executive order also directed the establishment of new methane and volatile organic compound standards applicable to existing oil and gas operations, including the production, transmission, processing and storage segments. Certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified offshore production sources.


The OCSLA authorized the DOI to regulate activities authorized by the BOEM in the Central and Western Gulf of Mexico.  EPA has air quality jurisdiction over all other parts of the OCS.  Under the OCSLA, DOI is limited to regulating offshore emissions of criteria and their precursor – pollutants to the extent they significantly affect the air quality of any state.


On May 14, 2020, the BOEM issued its final rule to update air quality regulations applicable to activities authorized by BOEM on the OCS in the Central and Western Gulf of Mexico.  This newly revised rule adopted changes such as incorporation of the definition of the NAAQS, updated Significance Levels (SLs), added new requirements for PM2.5 and PM10, updates to emissions exemption thresholds and revision to the Air Quality Spreadsheets.


Water Discharges.  The primary federal law for oil spill liability is the OPA which amends and augments oil spill provisions of the federal Water Pollution Control Act (the “Clean Water Act”).  OPA imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters, including the OCS or adjoining shorelines.  A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located.  OPA assigns joint and several, strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to 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 January 2018, the BOEM raised OPA’s damages liability cap to $137.7 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 $35.0 million and $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 $150.0 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 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 have 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. 


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 Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for our financial information.






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.


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, 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 operate under a comprehensive 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 create 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 continuously 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 less in our offices during peak COVID-19 outbreaks in the community.


Recruitment and Compensation.  We pride ourselves on providing an attractive compensation and benefits program that allows our employees to 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.





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: 








Exec/Sr. Manager

    20 %     80 %

Mid-Level Manager

    17 %     83 %


    48 %     52 %

All Other

    9 %     91 %


US Ethnicity


Exec/Sr. Manager


Mid-Level Manager




All Other



    40 %     6 %     12 %      

Black/African American

    20 %     8 %     24 %     5 %


          2 %     12 %     7 %

Native American

                      1 %

Two or more races

          2 %           1 %


    40 %     82 %     52 %     86 %


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 Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., 5718 Westheimer Road, Suite 700, Houston, Texas 77057 or by calling (713) 297-8024.  Information on our website is not a part of this Form 10-K.






Item 1A. Risk Factors


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


Market and Competitive 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 adversely affects 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.  Historically, oil, NGLs and natural gas prices have been volatile and subject to wide price fluctuations in response to domestic and global changes in supply and demand, economic and legal forces, events and uncertainties, and numerous other factors beyond our control, including:  



changes in global supply and demand for crude oil, NGLs and natural gas;


events that impact global market demand (e.g. the reduced demand following the COVID-19 pandemic);


the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and major oil producing countries; 

the price and quantity of imports of foreign crude oil, NGLs, natural gas and liquefied natural gas into the U.S.; 

acts of war, terrorism or political instability in oil producing countries; 


domestic and foreign governmental regulations and taxes;


political conditions and events, including embargoes and moratoriums, affecting oil-producing activities;


the level of domestic and global oil and natural gas exploration and production activities;


the level of global crude oil, NGLs and natural gas inventories;


adverse weather conditions;


technological advances affecting energy consumption and the availability and cost of alternative energy sources;


the price, availability and acceptance of alternative fuels; 


cyberattacks on our information infrastructure or systems controlling offshore equipment;
  activities by non-governmental organizations to restrict the exploration and production of oil and natural gas so as to minimize or eliminate future emissions of carbon dioxide, methane gas and other GHG; 
  the availability of pipeline and other transportation alternatives and third party processing capacity; and 

geographic differences in pricing.


These factors and the volatility of the energy markets, which we expect to continue, make it extremely difficult to predict future commodity prices with any certainty.


If crude oil, NGLs and natural gas prices decrease from their current levels, we may be required to further reduce the estimated volumes and future value associated with our total proved reserves or record impairments to the carrying values of our oil and natural gas properties.


Lower future 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.  Under the full cost method of accounting for oil and gas producing activities, a ceiling test is performed at the end of each quarter to determine if our oil and gas properties have been impaired. Capitalized costs of oil and gas properties are generally limited to the present value of future net revenues of proved reserves based on the average price of the 12-month period prior to the ending date of each quarterly assessment using the unweighted arithmetic average of the first-day-of-the-month price for each month within such period.  Impairments of our oil and gas properties are more likely to occur during prolonged periods of depressed crude oil, NGL and natural gas pricing, as we experienced in 2020. While we have not recorded an impairment of our oil and gas properties during the year-ended December 31, 2020, any further decreases in commodity pricing could cause an impairment, which would result in a non-cash charge to earnings.   





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 enter into oil and natural gas price commodity derivative positions with respect to a portion of our expected production.  See Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for 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 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 crude oil and natural gas 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 there is a widening of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements or the counterparties to the derivative contracts fail to perform under the terms of the contracts.


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 to acquire productive oil and natural gas properties and exploratory prospects than we are able or willing to pay or finance.  Finally, companies with larger financial resources may have a significant advantage in terms of 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. 


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


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, 2020, three fields, accounting for approximately 0.1 MMBoe (or 1%) of our 2020 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. 


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 realize revenue from those wells until arrangements were made to process or 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, gathering stations, and production facilities. In addition, certain third-party pipelines have submitted requests in the past to increase the fees they charge us to use these pipelines.  These increased fees, if approved, could adversely impact our revenues or increase our operating costs, either of which would adversely impact our operating profits, cash flows and reserves.




Operating Risks


Relatively short production periods for our Gulf of Mexico properties based on proved reserves subject us to high reserve replacement needs and require significant capital expenditures to replace our proved reserves at a faster rate than companies whose proved reserves have longer production periods.  If we are not able to obtain new oil and gas leases or replace reserves, we will not be able to sustain production at current levels, which may have a material adverse effect on our business, financial condition, or results of operations.


Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable in order to replace or grow our produced proved reserves.  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.  Proved reserves in the Gulf of Mexico generally have shorter reserve lives than proved reserves in many other producing regions of the United States in part due to the difference in rules related to booking proved undeveloped reserves between conventional and unconventional basins.  Our independent petroleum consultant estimates that 32% of our total proved reserves as of December 31, 2020 will be depleted within three years.  As a result, our need to replace proved reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their proved reserves over a similar time period, such as those producers who have a larger portion of their proved reserves in areas other than the Gulf of Mexico.  Historically, we have funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, capital markets securities offerings and bank borrowings.  The capital markets we have historically accessed may be constrained because of our leverage and also because, in recent years, institutional investors who provide financing to fossil fuel energy companies have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies, and we may not be able to develop, find or acquire additional proved reserves in sufficient quantities to sustain our current production levels or to grow production beyond current levels.   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 depleted reserves more difficult. 


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 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 drill our wells, 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 retentions. 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 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.




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, 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.  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. Accordingly, we cannot provide 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:


  increase our vulnerability to general adverse economic and industry conditions, including reduced demand during the COVID-19 pandemic; 
  limit our ability to fund future working capital requirements, capital expenditures and ARO, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets; 
  limit our opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt obligations or to comply with any restrictive terms of our debt obligations; 
  limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
  impair our ability to obtain additional financing in the future or require us to seek alternative financing, which may be more restrictive or expensive; and 
  place us at a competitive disadvantage compared to our competitors that have less debt. 





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:



make loans and investments;

incur additional indebtedness or issue preferred stock;


create certain liens;


sell assets;


enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;


consolidate, merge or transfer all or substantially all of the assets of our company;


engage in transactions with our affiliates;


pay dividends or make other distributions on capital stock or indebtedness; and


create unrestricted subsidiaries.


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 assurances in 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.  In 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, 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 BOEM’s formerly issued NTL #2016-N01, if it 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.  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 impact our liquidity adversely.


In addition, the U.S. Government imposes strict joint and several liability under the OCSLA on the various lessees of a federal oil and gas lease for lease obligations, including decommissioning activities, which means that any single co-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 unable to perform its decommissioning 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 decommissioning 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 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. 


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 and 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 require the acquisition of a permit or other approval before drilling or other regulated activity commences; restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; limit or prohibit exploration or drilling activities on certain lands lying within wilderness, wetlands, MPAs and other protected areas or that may affect certain wildlife, including marine species and endangered and threatened species; and impose substantial liabilities for pollution resulting from our operations.




Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties; loss of our leases; incurrence of investigatory, remedial or corrective obligations; and the imposition of injunctive relief, which could prohibit, limit or restrict our operations in a particular area.


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


New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement could significantly increase our capital expenditures and operating costs or could result in delays, limitations or cancelations to our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows.  See Business – Environmental Regulations under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental, marine species, and endangered and threatened species regulations.


The threat of climate change could result in increased costs and reduced demand for the oil and natural gas we produce, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.


The threat of climate change continues to attract considerable attention in the United States and foreign countries. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to eliminate such future emissions. As a result, our operations are subject to a series of regulatory, political and litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs.  See Part I, Item 1. “Business – Compliance with Environmental Regulations” for more discussion on the threat of climate and restriction of GHG emissions. The adoption and implementation of any international, federal, regional or state legislation, executive actions, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions on our operations or in areas where we produce oil and natural gas could result in increased compliance costs or costs of consuming fossil fuels, and thereby reduce demand for the oil and natural gas that we produce. Additionally, political, financial and litigation risks may result in us having to restrict, delay or cancel production activities, incur liability for infrastructure damages as a result of climatic changes, or impair the ability to continue to operate in an economic manner, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.  Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential customer use of substitutes to energy commodities may result in increased costs, reduced demand for oil and natural gas we produce, resulting in reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets.  Moreover, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal and biofuels) could reduce demand for the oil and natural gas we produce, which would lead to a reduction in our revenues.  Finally, increasing concentrations of GHG in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events.   


Item 1B. Unresolved Staff Comments








Item 2. Properties 


Our producing fields are located in federal and state waters in the Gulf of Mexico in water depths ranging from less than 10 feet up to 7,300 feet.  The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, with higher initial production rates relative to other domestic reservoirs. As of December 31, 2020, three of our fields located in the conventional shelf accounted for approximately 82% our proved reserves on an energy equivalent basis.  The following table provides information for these fields:



Proved Reserves as of December 31, 2020


Oil (MMBbls)


NGLs (MMBbls)


Natural Gas (Bcf)


Oil Equivalent (MMBoe)


Percent of Total Company Proved Reserves


Mobile Bay Properties

    0.1       11.9       403.3       79.3       54.9 %

Ship Shoal 349 (Mahogany)

    15.8       1.8       40.3       24.3       16.8 %
Fairway           2.2       75.0       14.7       10.2 %


The Mobile Bay Properties, Ship Shoal 349 (Mahogany), and Fairway are three areas of operations of major significance, which we define as having year-end proved reserves of 10% or more of the Company’s total proved reserves on an energy equivalent basis.  Each area of operation of major significance is described in detail below.  Unless indicated otherwise, “drilling” or “drilled” in the descriptions below refers to when the drilling reached target depth, as this measurement usually has a higher correlation to changes in proved reserves compared to using the SEC’s definition for completion.  Following are descriptions of these areas of operations: 


Mobile Bay Properties 


The Mobile Bay Properties consist of interests located off the coast of Alabama, in state coastal and federal Gulf of Mexico waters approximately 70 miles south of Mobile, Alabama.  The field area includes 16 Alabama state water lease blocks and four Federal OCS lease blocks.  These properties include seven major platforms and 27 flowing wells, in up to 50 feet of water.  Exxon first discovered Norphlet gas play in 1978 with the first gas production from the Mary Ann Field in 1988.  We acquired varied operated working interests ranging from 25% to 100% in nine producing fields from Exxon effective January 1, 2019, and we became the operator of the fields in December 2019.  During 2020, we completed the purchase of the remaining interest in two federal Mobile Bay fields from Chevron U.S.A. Inc. ("Chevron").  Cumulative field production through 2020 is approximately 698.3 MMBoe gross.  The Mobile Bay Properties produce from the Jurassic age Norphlet eolian sandstone at an average depth of 21,000’ total vertical depth.  As of December 31, 2020, 56 Norphlet wells have been drilled on the Mobile Bay Properties, 45 wells were successful and 27 wells are currently producing.  


We acquired the Mobile Bay Properties in August 2019 and included the results of operations effective September 1, 2019 within our Consolidated Results of Operations.  During September 2019 to December 2019, transitioning activities occurred to transfer operatorship of the Mobile Bay Properties from Exxon to W&T.  (Given the limited history and the change in operatorship, production volumes, realized prices received and production costs are omitted.)





Ship Shoal 349 Field (Mahogany)


Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, Louisiana.  The field area covers Ship Shoal federal OCS blocks 349 and 359, with a single production platform on Ship Shoal block 349 in 375 feet of water. Phillips Petroleum Company discovered the field in 1993.  We initially acquired a 25% working interest in the field from BP Amoco in 1999.  In 2003, we acquired an additional 34% working interest through a transaction with ConocoPhillips that increased our working interest to approximately 59%, and we became the operator of the field in December 2004.  In early 2008, we acquired the remaining working interest from Apache Corporation (“Apache”) and we now own a 100% working interest in this field except for an interest in one well owned in the Joint Venture Drilling Program.  Cumulative field production through 2020 is approximately 56.6 MMBoe gross.  This field is a sub-salt development with nine productive horizons below salt at depths up to 18,000 feet.  As of December 31, 2020, 31 wells have been drilled and 26 were successful.  Since acquiring an interest and subsequently taking over as operator, we have directly participated in drilling 17 wells with a 100% success rate.  During 2018, one well was completed which had been drilled to target depth during 2017, and in addition, two wells were drilled and completed during 2018.  During 2019, one well was drilled, completed and producing in 2019, and significant workover activities were done to increase production.  There was no additional drilling activity during 2020 at Ship Shoal 349.


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



Year Ended December 31,








Net Sales:


Oil (MBbls)

    1,939       2,444       1,719  

NGLs (MBbls)

    148       154       167  

Natural gas (MMcf)

    3,015       3,955       2,508  

Total oil equivalent (MBoe)

    2,590       3,257       2,307  

Total natural gas equivalents (MMcfe)

    15,539       19,545       13,841  

Average daily equivalent sales (Boe/day)

    7,076       8,925       6,320  

Average daily equivalent sales (Mcfe/day)

    42,456       53,547       37,920  

Average realized sales prices:


Oil ($/Bbl)

  $ 36.69     $ 58.27     $ 62.83  

NGLs ($/Bbl)

    14.46       21.96       31.14  

Natural gas ($/Mcf)

    1.92       2.53       3.41  

Oil equivalent ($/Boe)

    30.54       47.84       52.78  

Natural gas equivalent ($/Mcfe)

    5.09       7.97       8.80  

Average production costs: (1)


Oil equivalent ($/Boe)

  $ 4.98     $ 4.77     $ 4.87  

Natural gas equivalent ($/Mcfe)

    0.83       0.79       0.81  




Includes lease operating expenses and gathering and transportation costs.




 Fairway Field



The Fairway Field is comprised of Mobile Bay Area blocks 113 (Alabama State Lease #0531) and 132 (Alabama State Lease #0532) located in 25 feet of water, approximately 35 miles south of Mobile, Alabama.  We acquired our initial 64.3% working interest, along with operatorship, in the Fairway Field and associated Yellowhammer gas processing plant, from Shell Offshore, Inc. (“Shell”) in August 2011 and acquired the remaining working interest of 35.7% in September 2014.  Cumulative field production through 2020 is approximately 136.4 MMBoe gross.  The field was discovered in 1985 with Well 113 #1 (now called JA).  Development drilling began in 1990 and was completed in 1991 with the addition of four wells, each drilled from separate surface locations.  The five producing wells came on line in late 1991.  As of December 31, 2020, six wells have been drilled, one of which was a replacement well.  This field is a Norphlet sand dune trend development with one producing horizon at an approximate depth of 21,300 feet. 


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




Year Ended December 31,








Net Sales:


Oil (MBbls)

    9       9       9  

NGLs (MBbls)

    265       305       315  

Natural gas (MMcf)

    5,329       5,918       5,673  

Total oil equivalent (MBoe)

    1,162       1,300       1,270  

Total natural gas equivalents (MMcfe)

    6,973       7,802       7,621  

Average daily equivalent sales (Boe/day)

    3,175       3,563       3,480  

Average daily equivalent sales (Mcfe/day)

    19,051       21,375       20,880  

Average realized sales prices:


Oil ($/Bbl)

  $ 38.52     $ 62.25     $ 66.63  

NGLs ($/Bbl)

    8.43       15.83       24.93  

Natural gas ($/Mcf)

    1.94       2.52       3.12  

Oil equivalent ($/Boe)

    11.12       15.61       24.54  

Natural gas equivalent ($/Mcfe)

    1.85       2.60       4.09  

Average production costs: (1)


Oil equivalent ($/Boe)

  $ 11.35     $ 10.77     $ 9.38  

Natural gas equivalent ($/Mcfe)

    1.89       1.80       1.56  




Includes lease operating expenses and gathering and transportation costs.





 Proved Reserves


Our proved reserves were estimated by Netherland, Sewell & Associates, Inc (“NSAI”), our independent petroleum consultant, and amounts provided in this Form 10-K are consistent with filings we make with other federal agencies.  Our proved reserves as of December 31, 2020 are summarized below:



Total Energy-Equivalent Reserves (2)


Classification of Proved Reserves (1)

  Oil (MMBbls)     NGLs (MMBbls)     Natural Gas (Bcf)     Oil Equivalent (MMBoe)     Natural Gas Equivalent (Bcfe)     % of Total Proved     PV-10 (In millions)  

Proved developed producing

    19.4       15.6       510.4       120.1       720.4       83 %   $ 573.0  

Proved developed non-producing

    4.6       0.9       39.8       12.1       72.9       8 %     73.7  

Total proved developed

    24.0       16.5       550.2       132.2       793.3       91 %     646.7  

Proved undeveloped

    8.2       0.9       19.1       12.2       73.2       9 %     94.2  

Total proved

    32.2       17.4       569.3       144.4       866.5       100 %   $ 740.9  



In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2020 were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the year end December 31, 2020.  Applying this methodology, the West Texas Intermediate ("WTI") average spot price of $39.54per barrel and the Henry Hub natural gas average spot price of $1.985per million British Thermal Unit were utilized as the referenced price and after adjusting for quality, transportation, fees, energy content and regional price differentials, the average realized prices were $37.78 per barrel for oil, $10.29 per barrel for NGLs and $2.05 per Mcf for natural gas.  In determining the estimated realized price for NGLs, a ratio was computed for each field of the NGLs realized price compared to the crude oil realized price.  Then, this ratio was applied to the crude oil price using SEC guidance. Such prices were held constant throughout the estimated lives of the reserves. Future production and development costs are based on year-end costs with no escalations.



Totals may not compute due to rounding.  The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent price for oil and NGLs may differ significantly.


Neither PV-10 nor PV-10 after ARO are financial measures defined under GAAP; therefore, the following table reconciles these amounts to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.  Management believes that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant and useful for evaluating the relative monetary significance of oil and natural gas properties.  PV-10 and PV-10 after ARO are used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities.  We believe the use of pre-tax measures is valuable because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid.  Management believes that the presentation of PV-10 and PV-10 after ARO provide useful information to investors because they are widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies.  PV-10 and PV-10 after ARO are not measures of financial or operating performance under GAAP, nor are they intended to represent the current market value of our estimated oil and natural gas reserves.  PV-10 and PV-10 after ARO should not be considered in isolation or as substitutes for the standardized measure of discounted future net cash flows as defined under GAAP.  Investors should not assume that PV-10, or PV-10 after ARO, of our proved oil and natural gas reserves shown above represent a current market value of our estimated oil and natural gas reserves.





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



December 31, 2020


Present value of estimated future net revenues (PV-10)

  $ 740.9  

Present value of estimated ARO, discounted at 10%

    (204.2 )

PV-10 after ARO


Future income taxes, discounted at 10%

    (43.0 )

Standardized measure of discounted future net cash flows

  $ 493.7  


Changes in Proved Reserves 


Our total proved reserves at December 31, 2020 were 144.4 MMBoe compared to 157.4 MMBoe at December 31, 2019, representing an overall decrease of 13.0 MMBoe. Total proved reserves decreased by 27.7 MMBoe as a result of lower commodity prices and 15.4 MMBoe due to production.  Partially offsetting these decreases were increases in proved reserves of 26.2 MMBoe due to positive technical revisions (including increased well performance), 3.6 MMBoe related to acquisitions, 0.2 MMBoe related to extensions and discoveries. See Development of Proved Undeveloped Reserves below for a table reconciling the change in proved undeveloped reserves during 2020.  See Financial Statements and Supplementary Data– Note 20 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for additional information.


Our estimates of proved reserves, PV-10 and the standardized measure as December 31, 2020 are calculated based upon SEC mandated 2020 unweighted average first-day-of-the-month crude oil and natural gas benchmark prices, and adjusting for quality, transportation fees, energy content and regional price differentials, which may or may not represent current prices.  If prices fall below the 2020 levels, absent significant proved reserve additions, this may reduce future estimated proved reserve volumes due to lower economic limits and economic return thresholds for undeveloped reserves, as well as impact our results of operations, cash flows, quarterly full cost impairment ceiling tests and volume-dependent depletion cost calculations.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 in this Form 10-K for additional information.


Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process


Our estimated proved reserve information as of December 31, 2020 included in this Form 10-K was prepared by our independent petroleum consultants, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. 


We maintain an internal staff of reservoir engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates.  Additionally, our senior management reviews any significant changes to our proved reserves on a quarterly basis.  Our Director of Reservoir Engineering has over 30 years of oil and gas industry experience and has managed the preparation of public company reserve estimates the last 16 years.  He joined the Company in 2016 after spending the preceding 12 years as Director of Corporate Engineering for Freeport-McMoRan Oil & Gas.  He has also served in various engineering and strategic planning roles with both Kerr-McGee and with Conoco, Inc.  He earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1989 and a Master’s degree in Business Administration from the University of Houston in 1999.





Reserve Technologies


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



the quality and quantity of available data and the engineering and geological interpretation of that data;



estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;



the accuracy of various mandated economic assumptions such as the future prices of crude oil, NGLs and natural gas; and



the judgment of the persons preparing the estimates.


Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.


Reporting of Natural Gas and Natural Gas Liquids


We produce NGLs as part of the processing of our natural gas.  The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale.  We report all natural gas production information net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.  We convert barrels to Mcfe using an energy-equivalent ratio of six Mcf to one barrel of oil, condensate or NGLs.  This energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ substantially.



Development of Proved Undeveloped Reserves


Our PUDs were estimated by NSAI, our independent petroleum consultant.  Future development costs associated with our PUDs at December 31, 2020 were estimated at $94.2 million.


The following table presents changes in our PUDs (in MMBoe):



December 31,








Proved undeveloped reserves, beginning of year

    23.6       17.0       12.0  

Transfers to proved developed reserves

          (0.5 )     (5.0 )

Revisions of previous estimates

    (11.4 )     7.1       11.3  

Extensions and discoveries


Purchase of minerals in place


Sales of minerals in place

                (3.5 )

Proved undeveloped reserves, end of year

    12.2       23.6       17.0  





The following table presents our estimates as to the timing of converting our PUDs to proved developed reserves: 


Year Scheduled for Development


Number of PUD Locations


Percentage of PUD Reserves Scheduled to be Developed



    1       22 %


    2       15 %


    1       59 %
2024     1       4 %


    5       100 %


Activity related to PUD in 2020:



Net PUD revisions of 11.4 MMBoe were primarily due to price revisions at our Ship Shoal 028 and our Mahogany fields.


Activity related to PUDs in 2019:



Successfully drilled and converted two locations and 0.5 MMBoe from PUD to proved developed with total capital expenditures of $27.1 million during 2019.



Net PUD revisions of 7.1 MMBoe were primarily at our Ship Shoal 028 and our Mahogany fields.


We believe that we will be able to develop all but 2.3 MMBoe (approximately 19%) of the total 12.2 MMBoe classified as PUDs at December 31, 2020, within five years from the date such PUDs were initially recorded.  The exceptions are at the Mississippi Canyon 243 field ("Matterhorn") and Viosca Knoll 823 ("Virgo") deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability.  One sidetrack PUD location at each Matterhorn and Virgo, will be delayed until an existing well are depleted and available to sidetrack.  We also plan to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of the existing well.  Based on the latest reserve report, these PUD locations are expected to be developed in 2022 and 2024.







The following table summarizes our leasehold at December 31, 2020. Deepwater refers to acreage in over 500 feet of water:



Developed Acreage


Undeveloped Acreage


Total Acreage













Shelf     427,222       311,370       99,551       86,788       526,773       398,158  
Deepwater     159,209       62,067       50,451       45,651       209,660       107,718  


    586,431       373,437       150,002       132,439       736,433       505,876  


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


Regarding the undeveloped leasehold, of the total 132,439 net undeveloped acres none could expire in 2021; 960 net acres (1%) could expire in 2022; 37,166 net acres (28%) could expire in 2023; 80,293 net acres (60%) could expire in 2024; and 14,020 net acres (11%) could expire in 2025 and beyond.  In making decisions regarding drilling and operations activity for 2020 and beyond, we give consideration to undeveloped leasehold that may expire in the near term in order that we might retain the opportunity to extend such acreage.  


Our net acreage decreased 41,688 net acres (8%) from December 31, 2019 due to lease expirations and relinquishments, partially offset by acquisitions.




For the years 2020, 2019 and 2018, our net daily production averaged 42,046 Boe, 40,634 Boe, and 36,510 Boe, respectively.  Production increased in 2020 from 2019 primarily due a full year of production at the Mobile Bay properties.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations under Part II, Item 7 in this Form 10-K for additional information.


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



Year Ended December 31,








Net Sales:


Oil (MBbls)

    5,629       6,675       6,687  

NGLs (MBbls)

    1,696       1,271       1,307  

Oil and NGLs (MBbls)

    7,325       7,946       7,994  

Natural gas (MMcf)

    48,384       41,310       31,991  

Total oil equivalent (MBoe)

    15,389       14,831       13,326  

Total natural gas equivalents (MMcfe)

    92,334       88,987       79,956  






Productive Wells


The following presents our ownership interest at December 31, 2020 in our productive oil and natural gas wells. A net well represents our fractional working interest of a gross well in which we own less than all of the working interest:


Offshore Wells


Oil Wells (1)


Gas Wells (2)


Total Wells













Operated     85       74.1       67       58.8       152       132.9  
Non-operated     39       8.4       22       7.8       61       16.2  

Total offshore wells

    124       82.5       89       66.6       213       149.1  




Includes six gross (4.2 net) oil wells with multiple completions.




Includes three gross (2.5 net) gas wells with multiple completions.


Drilling Activity


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


Development and Exploration Drilling


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



Year Ended December 31,








Development Wells Completed:


Gross wells

          3.0       3.0  

Net wells

          1.6       1.5  

Exploration Wells Completed:


Gross wells

          3.0       3.0  

Net wells

          0.8       1.3  


 Our success rates related to our development and exploration wells drilled was 100% in both 2019 and 2018, with all wells drilled being productive and none were non-commercial (dry holes).  


Recent Drilling Activity


During 2020, we drilled one well, which we expect to be completed in 2021.


Capital Expenditures


See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Expenditures under Part II, Item 7 in this Form 10-K for capital expenditure information.





Item 3. Legal Proceedings


Appeal with ONRR.  In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance with the offset to a liability reserve; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals (“IBLA”) under the DOI.  On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties. We filed a motion for reconsideration of the IBLA decision on March 27, 2017.  Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana.  We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million in order to appeal the IBLA decision.  On December 4, 2018, the IBLA denied our motion for reconsideration.  On February 4, 2019, we filed our first amended complaint, and the government has filed its Answer in the Administrative Record.  On July 9, 2019, we filed an Objection to the Administrative Record and Motion to Supplement the Administrative Record, asking the court to order the government to file a complete privilege log with the record.  Following a hearing on July 31, 2019, the Court ordered the government to file a complete privilege log.  In an Order dated December 18, 2019, the court ordered the government to produce certain contracts subject to a protective order and to produce the remaining documents in dispute to the court for in camera review.  Ultimately, the court upheld the government’s assertion of privilege and the parties commenced briefing on the merits.  At this point, both parties have filed cross-motions for summary judgment and opposition briefs. W&T has filed a Reply in support of its Motion for Summary Judgment and the government has in turn filed its Reply brief.  With briefing now completed, we are waiting for the district court’s ruling on the merits.   In January 2020, the cash collateral in the amount of $6.9 million securing the appeal bond in this matter was released to us. In compliance with the ONRR’s request for W&T to increase the surety posted in the appeal, the penal sum of the bond posted is currently $8.2 million.


Monetary Sanctions by Government Authorities (Notices of Proposed Civil Penalty Assessment).  During 2020 and 2019, we did not pay any civil penalties to the Bureau of Safety and Environmental Enforcement (“BSEE”) related to Incidents of Noncompliance (“INCs”) at various offshore locations.  In January 2021, we executed a Settlement Agreement with BSEE which resolved nine pending civil penalties issued by BSEE. The civil penalties pertained to INCs issued by BSEE alleging regulatory non-compliance at separate offshore locations on various dates between July 2012 and January 2018, with the proposed civil penalty amounts totaling $7.7 million.  Under the Settlement Agreement, W&T will pay a total of $720,000 in three annual installments, with the first installment due in March 2021.  In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a period ending in 2022.


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


See Financial Statements and Supplementary Data - Note 18 – Contingencies under Part II, Item 8 in this Form 10-K for additional information on the matters described above.






Executive Officers of the Registrant


The following table lists our executive officers:



Age (1)



Tracy W. Krohn



Chairman, Chief Executive Officer and President

Janet Yang



Executive Vice President and Chief Financial Officer

William J. Williford



Executive Vice President and General Manager of Gulf of Mexico

Stephen L. Schroeder



Senior Vice President and Chief Technical Officer

Shahid A. Ghauri



Vice President, General Counsel and Corporate Secretary


(1)     Ages as of February 23, 2021


Tracy W. Krohn has served as our Chief Executive Officer since he founded the Company in 1983, President from 1983 until 2008 and again starting in March 2017, Chairman of the Board since 2004 and Treasurer from 1997 until 2006.  During 1996 to 1997, Mr. Krohn was Chairman and Chief Executive Officer of Aviara Energy Corporation.  He began his career as a petroleum engineer and offshore drilling supervisor with Mobil Oil Corporation and then as Senior Engineer with Taylor Energy Company.  Mr. Krohn serves on the board of directors for the American Petroleum Institute. He also serves on the board of directors of a privately owned company.


Janet Yang joined the Company in 2008 and was named Executive Vice President and Chief Financial Officer in November 2018.  Previously, she served as Acting Chief Financial Officer from August 2018 to November 2018, Vice President – Corporate and Business Development from March 2017 to November 2018, Director Strategic Planning & Analysis from June 2012 to March 2017 and Finance Manager from December 2008 to June 2012.  Prior to joining the Company, Ms. Yang held positions in research and investment analysis at BlackGold Capital Management, investment banking at Raymond James and energy trading at Allegheny Energy.


William J. Williford joined the Company in 2006 and was named Executive Vice President and General Manager of Gulf of Mexico in November 2018.  Since joining W&T in 2006, he has served as Reservoir Engineer, Exploration Project Manager, General Manager Deepwater of Gulf of Mexico, and most recently, Vice President and General Manager of Gulf of Mexico Shelf and Deepwater.  Mr. Williford has over 20 years of oil and gas technical experience with large independents in the Gulf of Mexico and Domestic Onshore.  Prior to joining the Company, Mr. Williford held positions in reservoir, production and operations at Kerr-McGee and Oryx Energy.


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


Shahid A. Ghauri joined the Company in March 2017 as Vice President, General Counsel and Corporate Secretary.  Prior to joining the Company, Mr. Ghauri served as a partner with Jones Walker, a New Orleans, Louisiana law firm since 2015.  Prior to that, Mr. Ghauri served as Assistant General Counsel of BHP Billiton Petroleum and in private practice as a partner working with top tier oil and gas firms for 17 years.  


Our management team's interests are highly aligned with those of our shareholders through our 34% stake in the Company's equity.


Item 4. Mine Safety Disclosures


             Not applicable.







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


Our common stock is listed and principally traded on the NYSE under the symbol “WTI.” As of March 2, 2021, there were 172 registered holders of our common stock.




During 2020 and 2019, no dividends were paid as dividend payments have been suspended.  Our Board of Directors decides the timing and amounts of any dividends for the Company.  Dividends are subject to periodic review of the Company’s performance, which includes the current economic environment and applicable debt agreement restrictions.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 and Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for more information regarding covenants related to dividends in our debt agreements.


Stock Performance Graph


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








Our peer group was revised in 2020 ("New Peer Group") to be in alignment with the peer group used for executive compensation analysis.  The New Peer Group no longer includes Abraxas Petroleum Corporation and Comstock Resources; however, Bonanza Creek Energy Inc.; Earthstone Energy Inc.; Gran Tierra Energy Inc.; Gulfport Energy Corporation; Highpoint Resources Corporation; Kosmos Energy Ltd.; Laredo Petroleum, Inc.; Northern Oil and Gas, Inc.; and Ring Energy, Inc. are still included.  Companies used in the most recent executive compensation analysis but were excluded due to not having a five year trading history were Talos Energy, Inc.; Berry Corporation; SilverBow Resources, Inc.; Penn Virginia Corporation; and Centennial Resource Development, Inc. Montage Resources Corporation was included in our compensation analysis, but excluded from the above graph as their stock was not traded during all of 2020 due to being acquired by Southwestern Energy Company. Additionally, the New Peer Group includes QEP Resources, Inc. 


Securities Authorized for Issuance under Equity Compensation Plans


The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.  For descriptions of the plans and additional information, see Financial Statements and Supplementary Data – Note 11 –Share-Based Awards and Cash-Based Awards under Part II, Item 8 in this Form 10-K.


Issuer Purchases of Equity Securities


For the year 2020, we did not purchase any of our equity securities.


The following table sets forth information about restricted stock units (“RSUs”) during the quarter ended December 31, 2020:




Total Number of Restricted Stock Units Delivered


Average Price per Restricted Stock Unit


Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs


Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs


October 1, 2020 – October 31, 2020

    N/A       N/A       N/A       N/A  

November 1, 2020 – November 30, 2020

    N/A       N/A       N/A       N/A  

December 1, 2020 – December 31, 2020 (1)

    260,751     $ 2.57       N/A       N/A  




RSUs delivered by employees during December 2020 to satisfy tax withholding obligations on the vesting of RSU.


Sales of Unregistered Equity Securities


We did not have any sales of unregistered equity securities during the fiscal year ended December 31, 2020 that we have not previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.






Item 6. Selected Financial Data




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



Year Ended December 31,












(In thousands, except per share data)


Consolidated Statement of Operations Information:





  $ 216,419     $ 399,790     $ 438,798     $ 340,010     $ 268,950  


    19,101       22,373       37,127       32,257       26,429  

Natural gas

    99,300       106,347       99,629       108,923       100,405  


    11,814       6,386       5,152       5,906       4,202  

Total revenues

    346,634       534,896       580,706       487,096       399,986  

Operating costs and expenses:


Lease operating expenses

    162,857       184,281       153,262       143,738       152,399  

Production taxes

    4,918       2,524       1,832       1,740       1,889  

Gathering and transportation

    16,029       25,950       22,382       20,441       22,928  

Depreciation, depletion and amortization

    97,763       129,038       131,423       138,510       194,038  

Asset retirement obligations accretion

    22,521       19,460       18,431       17,172       17,571  

Ceiling test write-down of oil and natural gas properties

    -       -       -       -       279,063  

General and administrative expenses

    41,745       55,107       60,147       59,744       59,740  

Derivative (gain) loss

    (23,808 )     59,887       (53,798 )     (4,199 )     2,926  

Total costs and expenses

    322,025       476,247       333,679       377,146       730,554  

Operating income (loss)

    24,609       58,649       247,027       109,950       (330,568 )

Interest expense, net

    61,463       59,569       48,645       45,521       84,382  

Gain on debt transactions

    (47,469 )     -       (47,109 )     (7,811 )     (123,923 )

Other expense (income), net

    2,978       188       (3,871 )     5,127       1,369  
(Loss) income before income tax (benefit) expense     7,637       (1,108 )     249,362       67,113       (292,396 )

Income tax (benefit) expense

    (30,153 )     (75,194 )     535       (12,569 )     (43,376 )
Net income (loss)   $ 37,790     $ 74,086     $ 248,827     $ 79,682     $ (249,020 )

Basic and diluted earnings (loss) per common share

  $ 0.26     $ 0.52     $ 1.72     $ 0.56     $ (2.60 )









Year Ended December 31,












(In thousands)


Consolidated Cash Flow Information:


Net cash provided by operating activities

  $ 108,509     $ 232,227     $ 321,763     $ 159,408     $ 14,180  

Net cash used in investing activities

    (47,616 )     (313,814 )     (66,385 )     (107,107 )     (82,396 )

Net cash provided by (used in) financing activities

    (49,600 )     80,727       (321,143 )     (23,479 )     53,038  



December 31,












(In thousands)


Consolidated Balance Sheet Information:


Cash and cash equivalents

  $ 43,726     $ 32,433     $ 33,293     $ 99,058     $ 70,236  

Oil and natural gas properties and other, net (1)

    686,878       748,798       515,421       579,016       547,053  

Total assets (1)

    940,582       1,003,719       848,866       907,580       829,726  

Long-term debt (including current portion)

    625,286       719,533       633,535       992,052       1,020,727  

Shareholders' deficit (1)

    (208,286 )     (249,365 )     (324,796 )     (573,508 )     (659,037 )




Ceiling test write-downs of $279.1 million was recorded in 2016.







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



December 31,












Reserve Data: (1)


Estimated net proved reserves


Oil (MMBbls)

    32.2       37.8       39.1       34.4       32.9  

NGLs (MMBbls)

    17.4       24.5       9.8       7.8       8.2  

Natural Gas (Bcf)

    569.3       571.1       210.5       192.2       197.8  

Total barrel equivalents (MMBoe)

    144.4       157.4       84.0       74.2       74.0  

Total natural gas equivalents (Bcfe)

    866.5       944.5       504.1       445.3       444.0  

Proved developed producing (MMBoe)

    120.1       122.3       53.9       54.5       47.3  

Proved developed non-producing (MMBoe)

    12.1       11.5       13.1       7.7       17.4  

Total proved developed (MMBoe)

    132.2       133.8       67.0       62.2       64.7  

Proved undeveloped (MMBoe)

    12.2       23.6       17.0       12.0       9.3  
Proved developed reserves as %     91.6 %     85.0 %     79.8 %     83.8 %     87.4 %

Reserve additions (reductions) (MMBoe):


Revisions (2)

    (1.4 )     (3.0 )     21.1       9.6       13.0  

Extensions and discoveries

    0.2       1.1       2.1       5.2        

Purchases of minerals in place

    3.6       90.1       3.4              

Sales of minerals in place (3)

                (3.5 )            


    (15.4 )     (14.8 )     (13.3 )     (14.6 )     (15.4 )

Net reserve additions (reductions)

    (13.0 )     73.4       9.8       0.2       (2.4 )



The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.



Revisions include changes due to price estimated for reserves held at year-end for each year presented.  Revisions in 2020 include estimated price revisions for all proved reserves and incorporate the impact of price change of the purchase of minerals in place from the date of purchase to December 31, 2020. 



In 2018, sales of minerals in place primarily relate to conveyance of interest in properties to Monza.  


See Financial Statements and Supplementary Data– Note 20 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for additional information.









Year Ended December 31,












Operating: (1)


Net sales:

Oil (MBbls)     5,629       6,675       6,687       7,064       7,201  
NGLs (MBbls)     1,696       1,271       1,307       1,382       1,542  
Oil and NGLs (MBbls)     7,325       7,946       7,994       8,446       8,743  
Natural gas (MMcf)     48,384       41,310       31,991       36,754       39,731  
Total oil equivalent (MBoe)     15,389       14,831       13,326       14,571       15,365  
Total natural gas equivalents (MMcfe)     92,334       88,987       79,956       87,428       92,188  
Average daily equivalent sales (Boe/day)     42,046       40,634       36,510       39,921       41,980  
Average daily equivalent sales (Mcfe/day)     252,279       243,801       219,057       239,528       251,879  

Average realized sales prices:

Oil ($/Bbl)   $ 38.45     $ 59.89     $ 65.62     $ 48.13     $ 37.35  
NGLs ($/Bbl)     11.26       17.60