# W&T OFFSHORE INC (WTI) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from W&T OFFSHORE INC's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1288403/000155837022003156/wti-20211231x10k.htm
Accession: 0001558370-22-003156
Filing date: 2022-03-09
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture.
Confidence: high

Company profile: /company/WTI/
All MD&A years: /company/WTI/mda/
Next year: /company/WTI/mda/fy2022/ (FY 2022)

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

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with Part I, Items 1 and 2 Business and Properties; Item 1A Risk Factors; and Item 7A Quantitative and Qualitative Disclosures About Market Risk and with Part II, Item 8 Financial Statements and Supplementary Data in this Annual Report. The following discussion and analysis includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Annual Report, particularly in Part I, Item 1A Risk Factors.

This section of this Annual Report generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report are incorporated by reference to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

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Overview

We are 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. We have grown through acquisitions, exploration and development and currently hold working interests in 43 offshore producing fields in federal and state waters (38 producing fields and 5 capable of producing). We currently have under lease approximately 606,000 gross acres (412,000 net acres) spanning across the OCS off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama State waters, 411,000 gross acres on the conventional shelf and approximately 187,000 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. We currently own interests in 144 offshore structures, 103 of which are located in fields that we operate. We currently own interest in 178 productive wells, 142 of which we operate. Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC, Aquasition II LLC, and W & T Energy VI LLC, Delaware limited liability companies and through our proportionately consolidated interest in Monza, as described in more detail in Financial Statements and Supplementary Data – Notes 4 and 5 under Part II, Item 8 in this Annual Report.

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:

[[GREPCENT_TABLE]]
[["","\u25cf","Exploiting existing and acquired properties to add additional reserves and production;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Exploring for reserves on our extensive acreage holdings and in other areas of the Gulf of Mexico;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Acquiring reserves with substantial upside potential and additional leasehold acreage complementary to our existing acreage position at attractive prices; and"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Continuing to manage our balance sheet in a prudent manner and continuing our track record of financial flexibility in any commodity price environment."]]
[[/GREPCENT_TABLE]]

​

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 be made to our plans.

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 and natural gas, and the NGLs extracted from the natural gas). In addition, the prices of goods and services used in our business can vary and impact our cash flows. During 2021, average realized commodity prices increased from those we experienced during 2020 and 2019. Our margins in 2021 increased from 2020 primarily due to higher average realized commodity prices, partially offset by higher operating expenses as a result of our cost-cutting efforts in 2021. We measure margins using Adjusted EBITDA as a percent of revenue, which is a not a financial measurement under GAAP. We have historically increased our reserves and production through acquisitions, our drilling programs, and other projects that optimize production on existing wells. Our production decreased 9.6% in 2021 from the prior year. Our proved reserves increased by 13.2 MMBoe in 2021, primarily due to the significant increase in commodity prices in 2021 as compared to 2020.

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Factors Affecting the Comparability of our Financial Condition and Results of Operations

Mobile Bay Transaction. During the second quarter of 2021, the Company’s wholly-owned special purpose subsidiary vehicles, A-I LLC and A-II LLC (or collectively the “Subsidiary Borrowers”), entered into the Subsidiary Credit Agreement providing for a secured term loan (“Term Loan”) in an initial aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by the Subsidiary Borrowers to (i) fund the acquisition of the Mobile Bay Properties and the Midstream Assets from the Company and (ii) pay fees, commissions and expenses in connection with the transactions contemplated by the Subsidiary Credit Agreement and the other related loan documents, including to enter into certain swap and put derivative contracts. This transaction is described in more detail under Financial Statements and Supplementary Data – Note 4 – Mobile Bay Transaction, under Part II, Item 8, of this Annual Report.

Hurricanes and Severe Weather. During the third quarter of 2021, our production from the U.S Gulf of Mexico was impacted due to precautionary shut-ins of facilities and evacuations primarily associated with Hurricane Ida. While Company assets and infrastructure did not suffer significant damage during the storm, unplanned costs of $5.8 million for minor repairs and restoring production, as well as evacuating employees and contractors, were incurred as a result of the hurricane and reflected in lease operating expense. For the year ended December 31, 2021, we estimate deferred production related to these storms was approximately 0.8 MMBoe per day. See Liquidity and Capital Resources – Insurance Coverage under this Item 7 in this Form 10-K for additional information.

Known Trends and Uncertainties

Volatility in Oil, NGL and Natural Gas Prices. Historically, the markets for oil and natural gas has been volatile. Our realized sales prices received for our crude oil, NGLs and natural gas production are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and international geopolitical and economic events. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

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During 2021, commodity prices experienced significant improvement, particularly crude oil prices, due to a confluence of factors that have provided positive developments to the overall pricing environment when compared to 2020. With some exceptions, pandemic-related travel restrictions have gradually eased as governments continue to have increasing access to vaccines that help reduce the spread of COVID-19. As restrictions continue to abate, there is renewed emphasis on improving economic activity to pre-pandemic levels while managing the risk of a resurgence in COVID-19. Meanwhile, commodity prices demonstrated resiliency during the year. Producers continued to show restraint in increasing their capital expenditures even as prices increased, thereby causing a muted response in supply as demand for commodities increased. Additionally, OPEC Plus remained committed to modest increases in production during the year as the global economy recovered.‌

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While the current outlook for commodity prices is favorable and our operations are no longer significantly impacted by confinement restrictions, the risk of disruption to our operations continues as the emergence of a new variant of COVID-19 could adversely impact our operations, or commodity prices could significantly decline from current levels. The ongoing COVID-19 outbreak continues to evolve and, during the fourth quarter of 2021, a new variant emerged, the Omicron variant. It is difficult to assess if it will cause meaningful disruptions in economic activity across the world and if there will be any significant impacts in demand for energy.

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The recent invasion of parts of Ukraine by Russia, and the impact of world sanctions against Russia and the potential for retaliatory acts from Russia, are world events that can result in potential commodities and securities market disruptions that could affect world oil and natural gas markets and the volatility of oil and gas commodity prices and thus impact the Company’s business, stock trading price and availability of capital. Additionally, while OPEC Plus remained committed to steady and predictable production increases throughout 2021, it is difficult to determine whether it will change its production output policy or whether its members will remain committed to the production quotas set by the organization as a result of these events.

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WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. NYMEX WTI daily spot crude oil prices averaged $68.14 per barrel during 2021, up from $39.16 barrel during 2020 (74% increase). The U.S. Energy Information Administration (“EIA”) in their Short-Term Energy Outlook issued in January 2022 projects average crude oil prices for WTI to increase to approximately $71.32 per barrel in 2022, and decrease in 2023 to approximately $63.50 per barrel. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. NYMEX Henry Hub spot prices averaged $3.89 per MMBtu during 2021, up from $2.03 per MMBtu during 2020. The EIA projects average natural gas prices for Henry Hub to decrease to approximately $3.94 per MMBtu in 2022, and decrease further in 2023 to approximately $3.77 per MMBtu. Global oil production is forecasted to outpace global oil consumption during 2022 resulting in rising global oil inventories. Oil market balances are subject to significant uncertainties which could keep oil prices volatile.

Prolonged period of weak commodity prices may create uncertainties in our financial condition and results of operations. Such uncertainties may include:

[[GREPCENT_TABLE]]
[["","\u25cf","ceiling test write-downs of the carrying value of our oil and gas properties;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","reductions in our proved reserves and the estimated value thereof;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","additional supplemental bonding and potential collateral requirements;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","reductions in our borrowing base under the Credit Agreement; and"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","our ability to fund capital expenditures needed to replace produced reserves, which must be replaced on a long-term basis to provide cash to fund liquidity needs described above."]]
[[/GREPCENT_TABLE]]

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Impairment of Oil and Natural Gas Properties. Under the full cost method of accounting that we use for our oil and gas operations, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on our Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, we utilize SEC Pricing when performing the ceiling test. At December 31, 2021, the Company’s ceiling test computation was based on SEC pricing of $65.25 per Bbl of oil, $3.68 per Mcf of natural gas and $26.83 per Bbl of NGLs.

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As part of our period end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs and operating expense assumptions, which we expect to decrease further as a result of sustained lower commodity prices. There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in Part I, Item 1A. Risk Factors. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties.

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Deferred Production. Our oil, NGLs and natural gas production is significantly affected by unplanned production downtime caused by events outside of our control and create uncertainties in our financial condition, cash flow and results of operations. Such events include third party downtime associated with non-operated properties and the transportation, gathering or processing of production and weather events.

Hurricane and Severe Weather Events. Since our operations are in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. We normally obtain insurance to reduce, but not totally mitigate, our financial exposure risk; however, affordable insurance coverage for property damage to our facilities for hurricanes is not assured. See Liquidity and Capital Resources – Insurance Coverage under this Item 7 in this Form 10-K for additional information. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural

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gas production and revenues, increased lease operating expense for evacuations and repairs and possible acceleration of plugging and abandonment costs.

Regulations. We are subject to a number of regulations from federal and state governmental entities, which are described under Part I, Item 1, Regulations in this Form 10-K. Our Company and others like us, are exposed to a number of risks by operating in the oil and gas industry in the Gulf of Mexico, which are described in Item 1A, Risk Factors, in this Form 10-K.

BOEM Matters. As of the filing date of this Form 10-K, the Company is in compliance with its financial assurance obligations to the BOEM and has no outstanding BOEM orders related to financial assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive demands in the future for financial assurances from the BOEM. For more information on the BOEM and financial assurance obligations to that agency, see Business – Compliance with Government Regulations – Decommissioning and financial assurance requirements under Part I, Item 1 of this Form 10-K.

Surety Bond Collateral. Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. In 2021 or 2020, we have not had to post collateral for sureties and we currently do not have any collateral posted for Surety Bonds. The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.

Consolidated Appropriations Act, 2021. Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. See Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8, and Liquidity and Capital Resources in this Item 7 of this Form 10-K for additional information.

Results of Operations

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Derivative income (expense)” in our Consolidated Statements of Operations. The following table presents our sources of revenue as a percentage of total revenue:

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","Year Ended December 31,"],["\u200b","2021","","2020"],["Oil","59.1","%","\u200b","62.4","%"],["NGLs","7.9","%","\u200b","5.5","%"],["Natural gas","31.1","%","\u200b","28.7","%"],["Other","1.9","%","\u200b","3.4","%"]]
[[/GREPCENT_TABLE]]

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The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices for the years ended December 31, 2021 and 2020 (in thousands):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","Year Ended December 31,","\u200b","\u200b","\u200b"],["\u200b","2021","","2020","\u200b","\u200b","Change"],["\u200b","(In thousands, except realized sales price data)"],["Revenues:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Oil","$","329,557","\u200b","$","216,419","\u200b","$","113,138"],["NGLs","","44,343","\u200b","","19,101","\u200b","","25,242"],["Natural gas","","173,749","\u200b","","99,300","\u200b","","74,449"],["Other","","10,361","\u200b","","11,814","\u200b","","(1,453)"],["Total revenues","$","558,010","\u200b","$","346,634","\u200b","$","211,376"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Production Volumes:","","","\u200b","","","\u200b"],["Oil (MBbls)","","4,998","\u200b","","5,629","\u200b","","(631)"],["NGLs (MBbls)","","1,450","\u200b","","1,696","\u200b","","(246)"],["Natural gas (MMcf)","","44,790","\u200b","","48,384","\u200b","","(3,594)"],["Total oil equivalent (MBoe)","","13,913","\u200b","","15,389","\u200b","","(1,476)"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average daily equivalent sales (Boe/day)","\u200b","38,118","","\u200b","42,046","\u200b","\u200b","(3,928)"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average realized sales prices:","\u200b","","","\u200b","","\u200b","","\u200b"],["Oil ($/Bbl)","$","65.94","\u200b","$","38.45","\u200b","$","27.49"],["NGLs ($/Bbl)","","30.59","\u200b","","11.26","\u200b","","19.33"],["Natural gas ($/Mcf)","","3.88","\u200b","","2.05","\u200b","","1.83"],["Oil equivalent ($/Boe)","","39.36","\u200b","","21.76","\u200b","\u200b","17.60"],["Oil equivalent ($/Boe), including realized commodity derivatives","\u200b","32.52","\u200b","\u200b","24.70","\u200b","","7.82"]]
[[/GREPCENT_TABLE]]

​

Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the years ended December 31, 2021 and 2020 (in thousands):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","Price","","Volume","\u200b","Total"],["Oil","$","137,392","\u200b","$","(24,254)","\u200b","$","113,138"],["NGLs","","28,017","\u200b","","(2,775)","\u200b","","25,242"],["Natural gas","","81,826","\u200b","","(7,377)","\u200b","","74,449"],["\u200b","$","247,235","\u200b","$","(34,406)","\u200b","$","212,829"]]
[[/GREPCENT_TABLE]]

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Realized Prices on the Sale of Oil, NGLs and Natural Gas. Our average realized crude oil sales price differs from the WTI benchmark average crude price due primarily to premiums or discounts, crude oil quality adjustments, and volume weighting (collectively referred to as differentials). Crude oil quality adjustments can vary significantly by field as a result of quality and location. For example, crude oil from our East Cameron 321 field normally receives a positive quality adjustment, whereas crude oil from our Mahogany field normally receives a negative quality adjustment. All of our crude oil is produced offshore in the Gulf of Mexico and is primarily characterized as Poseidon, Light Louisiana Sweet (“LLS”), and Heavy Louisiana Sweet (“HLS”). Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentials of WTI versus Poseidon, LLS and HLS for 2021 declined on average by approximately $0.63 - $1.13 per barrel compared to 2020 for these types of crude oils with the Poseidon having a negative differential and the LLS and HLS having positive differentials as measured on an index basis.

Two major components of our NGLs, ethane and propane, typically make up approximately 70% of an average NGL barrel. During 2021, average prices for domestic ethane increased by 62.7% and average domestic propane prices increased by 125.7% from 2020 as measured using a price index for Mount Belvieu. The changes in the average price for other domestic NGLs components in 2021 ranged from an increase of 100.9% to 103.7% year-over-year.

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The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

Oil, NGLs, and Natural Gas Volumes.  Production volumes decreased by 1,476 MBoe to 13,913 MBoe primarily due to adverse weather events during the 3rd quarter of 2021, well maintenance and natural declines. Deferred production for 2021 related to these named storms and maintenance events collectively resulted in deferred production of 2.2 MMBoe, compared to 2.8 MMBoe in 2020.

Operating Expenses

The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes:

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","Year Ended December 31,","\u200b","\u200b","\u200b"],["\u200b","2021","","2020","","\u200b","Change"],["\u200b","(In thousands, except per Boe data)"],["Operating expenses:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Lease operating expenses","$","174,582","\u200b","$","162,857","\u200b","$","11,725"],["Production taxes","","10,074","\u200b","","4,918","\u200b","","5,156"],["Gathering and transportation","","17,845","\u200b","","16,029","\u200b","","1,816"],["Depreciation, depletion, amortization and accretion","","113,447","\u200b","","120,284","\u200b","","(6,837)"],["Ceiling test write-down of oil and natural gas properties","","\u2014","\u200b","","\u2014","\u200b","","\u2014"],["General and administrative expenses","","52,400","\u200b","","41,745","\u200b","","10,655"],["Total operating expenses","$","368,348","\u200b","$","345,833","\u200b","$","22,515"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average per Boe ($/Boe):","","","\u200b","","","\u200b"],["Lease operating expenses","$","12.55","\u200b","$","10.58","\u200b","$","1.97"],["Gathering and transportation","","1.28","\u200b","","1.04","\u200b","","0.24"],["Production costs","","13.83","\u200b","","11.62","\u200b","","2.21"],["Production taxes","","0.72","\u200b","","0.32","\u200b","","0.40"],["DD&A","","8.15","\u200b","","7.82","\u200b","","0.33"],["G&A expenses","","3.77","\u200b","","2.71","\u200b","","1.06"],["Operating costs","$","26.47","\u200b","$","22.47","\u200b","$","4.00"]]
[[/GREPCENT_TABLE]]

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Lease operating expenses. Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of Mexico. These operating costs are comprised of several components, including direct or base lease operating expenses, insurance premiums, workover costs, facilities repairs and maintenance expenses, and hurricane repair expenses. Our lease operating costs, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased $11.7 million to $174.6 million in 2021 compared to $162.9 million in 2020. On a per Boe basis, lease operating expenses increased to $12.55 per Boe during 2021 compared to $10.58 per Boe during 2020. On a component basis, base lease operating expenses increased $5.0 million, workover expenses increased $1.8 million, facilities maintenance expenses increased $4.9 million, and hurricane repairs increased $1.0 million. These increases were partially offset by decrease of $1.0 million in insurance premiums.

Expenses for direct labor, materials and supplies, rental and third party costs comprise the most significant portion of our base lease operating expense. Base lease operating expenses increased primarily due to (i) a net increase in contract labor, equipment rental, and transportation costs of $3.6 million at various fields; (ii) increased incentive compensation costs related to field employees of $2.2 million; (iii) a reduction in credits to expense from prior period royalty adjustments of $1.5 million as compared to the prior period; and (iv) a reduction in credits to expense of $2.3 million received in prior period from the PPP funds; partially offset by (v) $4.6 million of reduced expenses related to fields that were no longer producing during the year ended December 31, 2021, cost savings from the consolidation of our two gas processing plants in Alabama, and other miscellaneous items.

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Workovers and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period.

Production taxes. Production taxes consist of severance taxes levied by the Alabama Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state, respectively. Production taxes were $10.1 million in 2021, an increase of $5.2 million as compared to 2020, primarily due to the increase in realized natural gas prices, partially offset by decreased natural gas production volumes.

Gathering and transportation costs. Gathering and transportation costs consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale. Gathering and transportation costs increased to $17.8 million in 2021 compared to $16.0 million in 2020 primarily due to lower costs in the prior year that were impacted by credits to expense associated with the finalization of the Mobile Bay acquisition.

Depreciation, depletion, amortization and accretion. Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. See Part II, Item 8. Financial Statements and Supplementary data — Note 1 — Summary of Significant Accounting Policies for further discussion. Accretion expense is the expensing of the changes in value of our asset retirement obligations as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. DD&A, which includes accretion for ARO, increased to $8.15 per Boe in 2021 from $7.82 per Boe in 2020. On a nominal basis, DD&A decreased to $113.4 million in 2021 from $120.3 million in 2020. The rate per Boe increased year-over-year mostly as a result of increases in the future development costs included in the depreciable base compared to the relatively smaller increase in proved reserves over the comparable prior year period.

General and administrative expenses (“G&A”). G&A expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity based compensation expense, audit and other fees for professional services and legal compliance. For 2021, G&A expenses were $52.4 million compared to $41.7 million in 2020. The increase in 2021 G&A expense compared to 2020 was primarily due to (i) a net increase of $4.4 million increase in legal costs and other miscellaneous expenses primarily related to credits to expense in the prior period to adjust for the final settlement of BEE civil penalties; (ii) a net increase of $3.4 million in payroll and incentive compensation expenses as share based compensation expense and cash incentive compensation expense did not occur in the prior period; (iii) a reduction in overhead allocations to partners (credits to expense) of $0.7 million; (iv) credits related to the PPP funds received in the prior period; partially offset by (v) the $2.1 million employee retention credit recognized during the first quarter of 2021. See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1, and Liquidity and Capital Resources in this Item 2 of this Quarterly Report for additional information on the employee retention credit.

Other Income and Expense

The following table presents the components of other income and expense for the periods presented and corresponding changes:

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","Year Ended December 31,","\u200b","\u200b","\u200b"],["\u200b","2021","","2020","","\u200b","Change"],["\u200b","(In thousands)"],["Other income and expenses:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Derivative loss (gain)","$","175,313","\u200b","$","(23,808)","\u200b","$","199,121"],["Interest expense, net","","70,049","\u200b","","61,463","\u200b","","8,586"],["Gain on debt transactions","","\u2014","\u200b","","(47,469)","\u200b","","47,469"],["Other (income) expense, net","","(6,165)","\u200b","","2,978","\u200b","","(9,143)"],["Income tax (benefit) expense","","(8,057)","\u200b","","(30,153)","\u200b","","22,096"]]
[[/GREPCENT_TABLE]]

​

Derivative loss (gain). We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as

44

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commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. Changes in the fair value and settlements are recorded on the Consolidated Statements of Operations in Derivative loss (gain) as an unrealized loss (gain) and a realized loss (gain), respectively. Additionally, we amortize derivative cash premiums paid for options over the life of the related contract on the Consolidated Statements of Operations in Derivative loss (gain) as a component of realized loss.

​

During 2021, a $175.3 million derivative loss was recorded for crude oil and natural gas derivative contracts. Of the total derivative loss, approximately $80.1 million and $95.2 million were associated with the unrealized loss and realized loss, respectfully. The realized derivative loss recorded in 2021 includes approximately $5.1 million of derivative premium amortization. The remaining realized derivative loss and unrealized derivative loss were primarily due to crude oil and natural gas prices rising throughout 2021 as compared to prices as of December 31, 2020, which decreased the estimated fair value of open contracts and decreased the settlement value of closed contracts. During 2020, a $23.8 million derivative gain was recorded for crude oil and natural gas derivative contracts. The total derivative gain includes a $33.4 million realized derivative gain offset by a $9.6 million unrealized derivative loss. The realized derivative gain recorded in 2020 was primarily due to crude oil prices falling during the second quarter of 2020 to historic lows, which increased the settlement value of closed contracts; the realized derivative gain was offset by $1.9 million of derivative premium amortization. The unrealized derivative loss in 2020 is primarily due to crude oil prices rising in the latter months of 2020, which decreased the estimated fair value of open contracts. See Financial Statements and Supplementary Data – Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

​

Interest expense, net. We finance a portion of our working capital requirements, capital expenditures and acquisitions with term-based debt and, from time to time, borrowings under our Credit Agreement. As a result, we may incur interest expense that is affected by both fluctuations in interest rates and the amount of debt outstanding. Interest expense includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, performance bond premiums and annual agency fees. Interest expense is presented net of any interest income we may receive. Interest expense, net, was $70.0 million in 2021, increasing $8.7 million from $61.5 million in 2020. The increase is primarily due to interest expense on the principal balance of the Term Loan, lower interest income between the two periods, and a reduction in credits to interest expense related to the PPP funds received in the prior period; partially offset by reductions to outstanding borrowings (lower interest expense) under the Credit Agreement during 2021 and a full year of reduced interest on the lower principal balance of the Senior Second Lien Notes. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information on our debt.

​

Gain on debt transactions. During 2020, the repurchase of a portion of our Senior Second Lien Notes resulted in a gain of $47.5 million for 2020. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

Other (income) expense, net. During 2021, other income, net, was $6.2 million, compared to $3.0 million of other expense, net, for 2020. For 2021, the amount primarily consists of other income related to the release of restrictions on the Black Elk Escrow fund, partially offset by expenses for net abandonment obligations pertaining to a number of legacy Gulf of Mexico properties and the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program. For 2020, the amount primarily consisted of expenses related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program. See Financial Statements and Supplementary Data – Note 9 – Restricted Deposits for ARO in Part II, Item 8 in this Form 10-K for additional information regarding the release of the Black Elk Escrow restrictions. See Financial Statements and Supplementary Data – Note 18 – Contingencies in Part II, Item 8 in this Form 10-K for additional information regarding the asset retirement obligations recorded for legacy properties.

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Income tax benefit (expense). Our income tax benefit for 2021 and 2020 was $8.1 million and $30.2 million, respectively. For 2021, our annual effective tax rate of 16.3% differed from the federal statutory rate of 21% primarily due to changes in our valuation allowance on our interest expense limitation carryover. Our effective tax rate for 2020 was not meaningful, and our income tax benefit was primarily due to the enactment of the Coronavirus Aid, Relief and Economic Security Act (“Cares Act”) on March 27, 2020 and the issuance by the United States Treasury Department (Treasury) of final and proposed regulations under Internal Revenue Code (“IRC”) Section 163(j) on July 28, 2020 that provided additional guidance and clarification to the business interest expense limitation.

During 2021, our valuation allowance increased $2.0 million primarily due to an increase in our disallowed interest expense limitation carryover. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

The Company assesses available positive and negative evidence regarding our ability to realize our deferred tax assets including reversing temporary differences and projections of future taxable income during the periods in which those temporary differences become deductible, as well as negative evidence such as historical losses. Assumptions about our future taxable income are consistent with the plans and estimates used to manage our business. Although the Company incurred a loss in 2021, we determined that these results were not indicative of future results and concluded that the positive evidence outweighed the negative evidence although any changes in forecasted taxable income could have a material impact on this analysis. The portion of the valuation allowance remaining relates to state net operating losses, charitable contributions carryover and the disallowed interest limitation carryover under IRC section 163(j). As of December 31, 2021, the Company’s valuation allowance was $24.4 million.

Liquidity and Capital Resources

Liquidity Overview

Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. We fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings, make related interest payments and satisfy our AROs. We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings.

The primary sources of our liquidity are cash from operating activities and borrowings under our Credit Agreement. As of December 31, 2021, we had $245.8 million of available cash and $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million. Subsequent to December 31, 2021, we have agreed to an extension of the Credit Agreement with Calculus Lending until January 3, 2023. See discussion in Credit Agreement below.

We believe that we will have adequate liquidity from cash flow from operations to fund our capital expenditure plans for 2022, fund our ARO spending for 2022 and fulfill our various other obligations. Availability under our Credit Agreement as of December 31, 2021 was $50.0 million. Our preliminary capital expenditure budget for 2022 has been established in the range of $70.0 million to $90.0 million, which includes our share of the Joint Venture Drilling Program, and excludes acquisitions. In our view of the outlook for 2022, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2022 and beyond while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to cover our liquidity requirements and we expect additional financing sources to be available if needed. If our liquidity becomes stressed from significant reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital expenditure projects and if prices improve, we may increase our investments. Beyond 2022, while we expect to continue to have adequate liquidity from cash flow from operations to fulfill our future obligations, we continue to evaluate financing and refinancing alternatives on a strategic basis.

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Sources and Uses of Cash 

The following table summarizes cash flows provided by (used in) by type of activity for the following periods:

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,","\u200b","\u200b","\u200b"],["\u200b","","2021","\u200b","2020","","\u200b","Change"],["\u200b","\u200b","(In thousands)"],["Operating activities","","$","133,668","\u200b","$","108,509","\u200b","$","25,159"],["Investing activities","\u200b","","(27,444)","\u200b","","(47,616)","\u200b","","20,172"],["Financing activities","\u200b","","100,266","\u200b","","(49,600)","\u200b","","149,866"]]
[[/GREPCENT_TABLE]]

​

Operating activities. Net cash provided by operating activities for 2021 was $133.7 million, increasing $25.2 million from 2020. The change between periods is primarily due to increased realized prices for crude oil, NGLs and natural gas, partially offset by decreased volumes, increased derivative settlement payments, and increased spending for ARO activities. Our combined average realized sales price per Boe increased 80.9% in 2021, which caused total revenues to increase $247.2 million, partially offset by decreases of 9.6% in overall production volumes which caused revenues to decrease by $34.4 million.

Other items affecting operating cash flows for 2021 were: ARO settlements of $27.3 million, which increased from $3.3 million in 2020; cash advances from joint venture partners of $7.8 million during 2021 compared to $2.0 million during 2020; derivative cash payments, net, were $81.3 million in 2021 compared to derivative cash receipts, net, of $45.2 million in 2020; and derivative premiums of $40.5 million were paid in 2021.

Investing activities. Net cash used in investing activities during 2021 and 2020 was $27.4 million and $47.6 million, respectively, which represents our acquisitions and investments in oil and gas properties and equipment. Investments in oil and natural gas properties (including changes in operating assets and liabilities associated with investing activities) during 2021 decreased $17.4 million from 2020 primarily due to less capital projects being undertaken in 2021 as compared to 2020. During 2020, the acquisition of property interest of $2.9 million was primarily related to the additional working interest acquisitions at the Mobile Bay Properties and Magnolia field. There were no significant acquisitions in 2021. There were no asset sales of significance in 2021 or 2020. See discussion in Capital Expenditures below.

Financing activities. Net cash provided by financing activities for 2021 was $100.3 million and net cash used in financing activities for 2020 was $49.6 million. During 2021, net cash provided by financing activities included the proceeds from the Term Loan of $215.0 million, offset by $9.8 million of debt issue costs incurred related to the Term Loan and the Ninth Amendment to the Credit Agreement, the repayment of $80.0 million of borrowings under the Credit Agreement and repayments of $24.1 million of the Term Loan. During 2020, net cash used in financing activities was from repayments of funds borrowed under the Credit Agreement and the purchase of the Senior Second Lien Notes, offset by borrowings under the Credit Agreement. The purchase of the Senior Second Lien Notes are disclosed in Financial Statements and Supplementary Data - Note 2 – Debt under Part II, Item 8 in this Form 10-K.

Joint Venture Drilling Program. To provide additional financial flexibility, we created the Joint Venture Drilling Program with private investors during 2018. The Joint Venture Drilling Program enables W&T to receive returns on its investment on a promoted basis and enables private investors to participate in certain drilling projects. It also allows more projects to be taken on with our capital expenditures budget and reduces our risk via diversification. In the Joint Venture Drilling Program, four wells came on line during 2018 and five came on line during 2019. During 2020, one well was drilled, which we completed in March 2022. See Financial Statements and Supplementary Data – Note 5 – Joint Venture Drilling Program under Part II, Item 8 in this Form 10-K for additional information on the Joint Venture Drilling Program.

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Derivative financial instruments. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. During 2021 and 2020, we entered into commodity contracts for crude oil and natural gas which related to a portion of our expected production for the time frames covered by the contracts. As of December 31, 2021, we had outstanding open derivatives for crude oil and natural gas. See Financial Statements and Supplementary Data – Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information. The following table summarizes the historical results of our realized hedging activities:

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","","Year Ended December 31,"],["\u200b","\u200b","2021","\u200b","2020"],["Crude Oil ($/Bbl):","","\u200b","","","\u200b"],["Average realized sales price, before the effects of derivative settlements","\u200b","$","65.94","\u200b","$","38.45"],["Effects of realized commodity derivatives","\u200b","","(10.44)","\u200b","","6.48"],["Average realized sales price, including realized commodity derivatives","\u200b","$","55.50","\u200b","$","44.93"],["Natural Gas ($/Mcf)","\u200b","","","\u200b"],["Average realized sales price, before the effects of derivative settlements","\u200b","$","3.88","\u200b","$","2.05"],["Effects of realized commodity derivatives","\u200b","","(0.96)","\u200b","","(0.05)"],["Average realized sales price, including realized commodity derivatives","\u200b","$","2.92","\u200b","$","2.00"]]
[[/GREPCENT_TABLE]]

​

Income taxes. As of December 31, 2021, we have current income taxes payable of $0.1 million. During 2021, we did not receive any income tax refunds. For 2021, we did not make any significant income tax payments. Additionally, we do not anticipate making any significant tax payments for 2022.

​

Dividends. During 2021, 2020 and 2019, we did not pay any dividends and a suspension of dividends remains in effect.

Discretionary Bonus to Employees Approved in February 2021. On February 15, 2021, the Company received approval from the Compensation Committee of the Board of Directors for the one-time payment of a discretionary cash bonus in the amount of $7.0 million, paid in equal installments on March 15, 2021 and April 15, 2021, subject to employment on those dates.

Employee Retention Credit. Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. The Company recognized a $2.1 million employee retention credit during the year ended December 31, 2021 which is included as a credit to General and administrative expenses in the Consolidated Statement of Operations.

Capital Expenditures

Our preliminary capital expenditure budget for 2022 has been established in the range of $70.0 million to $90.0 million, which includes our share of the Joint Venture Drilling Program and excludes acquisitions. We strive to maintain flexibility in our capital expenditure projects and if prices improve, we may increase our investments. We have flexibility in our capital expenditure programs as we have no long-term rig commitments and our current commitments with partners are short term.

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

​

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,"],["\u200b","","2021","","2020"],["\u200b","","(In thousands)"],["Exploration (1)","\u200b","$","18,273","\u200b","$","1,837"],["Development (1)","\u200b","","9,478","\u200b","","11,109"],["Acquisitions of interests (2)","\u200b","","661","\u200b","","2,919"],["Seismic and other","\u200b","","4,311","\u200b","","4,686"],["Investments in oil and gas property/equipment \u2013 accrual basis","\u200b","$","32,723","\u200b","$","20,551"]]
[[/GREPCENT_TABLE]]

​

[[GREPCENT_TABLE]]
[["","(1)","Reported geographically in the subsequent table."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","(2)","Various working interest acquisitions in 2020 and 2021 including the purchase of additional working interest at the Magnolia field the Mobile Bay Properties during 2020."]]
[[/GREPCENT_TABLE]]

​

The following table presents our exploration and development capital expenditures geographically:

​

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,"],["\u200b","","2021","","2020"],["\u200b","","(In thousands)"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Conventional shelf (1)","\u200b","$","7,872","\u200b","$","10,247"],["Deepwater","\u200b","","19,879","\u200b","","2,699"],["Exploration and development capital expenditures \u2013 accrual basis","\u200b","$","27,751","\u200b","$","12,946"]]
[[/GREPCENT_TABLE]]

​

[[GREPCENT_TABLE]]
[["","(1)","Includes exploration and development capital expenditures in Alabama state waters."]]
[[/GREPCENT_TABLE]]

​

The capital expenditures reported in the above two tables are included within Oil and natural gas properties and other, net on the Consolidated Balance Sheets. The capital expenditures reported within the Investing section of the Consolidated Statements of Cash Flows include adjustments for payments related to capital expenditures.

The following table sets forth our drilling activity for completed wells on a gross basis:

​

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Completed"],["\u200b","","2021","","2020","","2019"],["Offshore \u2013 gross wells drilled:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Conventional shelf","","\u2014","","\u2014","","3"],["Deepwater","","\u2014","","\u2014","","3"],["Wells operated by W&T","","\u2014","","\u2014","","5"]]
[[/GREPCENT_TABLE]]

​

We had a 100% success rate in 2019. During 2020, we drilled one well, which we completed in March 2022. All of the wells drilled in 2019 and 2020 are in the Joint Venture Drilling Program. During 2021, we participated in the drilling of an exploration well which we do not plan to complete.

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

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

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Lease Acquisitions. Over the last three years, we have acquired 23 leases for approximately $5.0 million from the BOEM in the Federal Offshore Lease Sales. We acquired 4 leases ($1.2 million) and 17 leases ($3.8 million) in the years 2020 and 2019, respectively. During 2021, we were the high bidder of two leases in Federal Offshore Lease Sale 257. In January 2022, a U.S District Court issued an order that could invalidate these leases. We are evaluating the court’s opinion and considering our options, which could include participating in an appellate process with peer companies and industry groups. If we are ultimately awarded, we will pay approximately $0.3 million for the awarded leases combined, which reflect a 100% working interest in the acreage.

Divestitures. From time to time, we sell various oil and gas properties for a variety of reasons including, change of focus, perception of value and to reduce debt, among other reasons. In 2021 and 2020, there were no property sales of significance. See Financial Statements and Supplementary Data – Note 6 –Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information on this divestiture.

Asset retirement obligations. Annually, we review and revise our ARO estimates. Our ARO at December 31, 2021 and 2020 were $424.5 million and $392.7 million, respectively, recorded using discounted values. We spent $27.3 million in 2021 and $3.3 million in 2020 for ARO and our estimate of ARO spending in 2022 is $55.0 million to $75.0 million. During 2021 and 2020, we revised our estimates of costs anticipated to be charged by service providers for plugging and abandonment projects and revised estimated to actual spending as invoices were processed and projects completed. As these estimates are for work to be performed in the future, and in many cases, several years in the future, actual expenditures could be substantially different than our estimates. Additionally, we revise our estimates to account for the cost to comply with any new or revised regulations, including increases in work scope and cost changes from interpretation of work scope. See Risk Factors – Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico under Part I, Item 1A and Financial Statements and Supplementary Data – Note 7 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.

Debt

We are actively monitoring the debt capital markets, and we intend to seek financings with longer tenors and market based covenants to continue to provide working and potential acquisition capital as well as provide funding for refinancing of some or all of our Second Lien Notes. The terms of such financings, which may replace or augment our Credit Agreement and refinance some or all of our Second Lien Notes, may vary significantly from those under the Credit Agreement and our Second Lien Notes.

The primary terms of our long-term debt, the conditions related to incurring additional debt, and the conditions and limitations concerning early repayment of certain debt are disclosed in Financial Statements and Supplementary Data –Note 2 – Debt under Part II, Item 8 in this Form 10-K.

Term Loan. As of December 31, 2021, we had $190.9 million of Term Loan principal outstanding. The Term Loan requires quarterly amortization payments, bears interest at a fixed rate of 7% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and its subsidiaries other than the Subsidiary Borrowers (and the subsidiary that owns the equity of the Subsidiary Borrowers), and is not secured by any assets other than first lien security interests in the equity in the Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

Credit Agreement. As of December 31, 2021, we had no borrowings outstanding under the Credit Agreement. During the year ended December 31, 2021, we repaid $80.0 million of borrowings.

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On November 2, 2021, the Company entered into two amendments to the Credit Agreement which effectively terminated the Company’s existing reserve based lending relationship with commercial bank lenders who have traditionally provided the Company’s revolving credit facility and established the Calculus Lending facility under the Credit Agreement. The Company has not had any borrowings under the Credit Agreement since the closing of the Mobile Bay Transaction in May 2021. The Company currently has no borrowings outstanding under the new Credit Agreement. On March 8, 2022 the Company entered into the Tenth Amendment to Sixth Amended and Restated Credit Agreement and Extension Agreement, which extended the maturity date and Lender commitment to January 3, 2023. Generally, we must be in compliance with the covenants in our Credit Agreement in order to access borrowings. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 of this Form 10-K for additional information concerning these recent two amendments to the Credit Agreement and the Calculus Lending facility.

Senior Second Lien Notes. As of December 31, 2021, we had $552.5 million principal outstanding of Senior Second Lien Notes with an interest rate of 9.75% per annum that mature on November 1, 2023. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

Debt Covenants. The Term Loan, Credit Agreement, and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Subsidiary Credit Agreement, the Credit Agreement and the indenture related to the Senior Second Lien Notes. We were in compliance with all applicable covenants of the Term Loan, Credit Agreement and the Senior Second Lien Notes indenture as of and for the period ended December 31, 2021. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

The Subsidiary Borrowers

On May 19, 2021, we formed A-I LLC and A-II LLC, both indirect, wholly-owned subsidiaries of W&T Offshore, Inc., through their parent, Aquasition Energy LLC (collectively, the Aquasition Entities”). Concurrently, A-I LLC and A-II II LLC, entered into a credit agreement providing for the Term Loan in an initial aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by A-I LLC and A-II LLC to fund the acquisition of the Mobile Bay Properties and the Midstream Assets, respectively, from the Company. The Term Loan is non-recourse to the Company and any subsidiaries other than the Aquasition Entities, and is secured by the first lien security interests in the equity of the Aquasition Entities and a first lien mortgage security interest in the Mobile Bay Properties. The See Financial Statements and Supplementary Data – Note 4 – Mobile Bay Transaction under Part II, Item 8 in this Annual Report for additional information.

At that time, we designated the Aquasition Entities as unrestricted subsidiaries under Indenture governing Senior Second Lien Notes (the “Unrestricted Subsidiaries”). Having been so designated, the Unrestricted Subsidiaries do not guarantee the Senior Second Lien Notes and the liens on the assets sold to the Unrestricted Subsidiaries have been released under the Credit Agreement. The Unrestricted Subsidiaries are not bound by the covenants contained in the Credit Agreement or the Senior Second Lien Notes. Under the Subsidiary Credit Agreement and related instruments, assets of the Aquasition Entities may not be available to mortgage or pledge as security to secure new indebtedness of the Company and its other subsidiaries. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

​

​

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Below is consolidating balance sheet information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Consolidated Balance Sheet as of December 31, 2021 (in thousands):

​

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Consolidated Balance Sheet","\u200b","Eliminations of Unrestricted Subsidiaries","\u200b","Consolidated Balance Sheet of restricted subsidiaries"],["Assets","","\u200b","","","\u200b","","","\u200b"],["Current assets:","","\u200b","","","\u200b","","","\u200b"],["Cash and cash equivalents","\u200b","$","245,799","\u200b","$","(38,937)","\u200b","$","206,862"],["Restricted cash","\u200b","\u200b","4,417","\u200b","\u200b","\u2014","\u200b","\u200b","4,417"],["Receivables:","\u200b","","","\u200b","","","\u200b"],["Oil and natural gas sales","\u200b","","54,919","\u200b","","(34,420)","\u200b","","20,499"],["Joint interest, net","\u200b","","9,745","\u200b","","10,856","\u200b","","20,601"],["Total receivables","\u200b","","64,664","\u200b","","(23,564)","\u200b","","41,100"],["Prepaid expenses and other assets","\u200b","","43,379","\u200b","","(356)","\u200b","","43,023"],["Total current assets","\u200b","","358,259","\u200b","","(62,857)","\u200b","","295,402"],["Oil and natural gas properties and other, net","\u200b","","665,252","\u200b","","(272,747)","\u200b","","392,505"],["Restricted deposits for asset retirement obligations","\u200b","","16,019","\u200b","","\u2014","\u200b","","16,019"],["Deferred income taxes","\u200b","","102,505","\u200b","","\u2014","\u200b","","102,505"],["Other assets","\u200b","","51,172","\u200b","","19,903","\u200b","","71,075"],["Total assets","\u200b","$","1,193,207","\u200b","$","(315,701)","\u200b","$","877,506"],["Liabilities and Shareholders\u2019 Deficit","\u200b","","","\u200b","","","\u200b"],["Current liabilities:","\u200b","","","\u200b","","","\u200b"],["Accounts payable","\u200b","$","82,481","\u200b","$","(29,678)","\u200b","$","52,803"],["Undistributed oil and natural gas proceeds","\u200b","","36,243","\u200b","","(3,144)","\u200b","","33,099"],["Asset retirement obligations","\u200b","","56,419","\u200b","","\u2014","\u200b","","56,419"],["Accrued liabilities","\u200b","","106,140","\u200b","","(29,937)","\u200b","","76,203"],["Current portion of long-term debt","\u200b","\u200b","42,960","\u200b","\u200b","(42,960)","\u200b","\u200b","\u2014"],["Income tax payable","\u200b","","133","\u200b","","\u2014","\u200b","","133"],["Total current liabilities","\u200b","","324,376","\u200b","","(105,719)","\u200b","","218,657"],["Long-term debt","\u200b","","","\u200b","","","\u200b"],["Principal","\u200b","","700,359","\u200b","","(147,899)","\u200b","","552,460"],["Unamortized debt issuance costs","\u200b","","(12,421)","\u200b","","7,546","\u200b","","(4,875)"],["Long-term debt, net","\u200b","","687,938","\u200b","","(140,353)","\u200b","","547,585"],["Asset retirement obligations, less current portion","\u200b","","368,076","\u200b","","(54,515)","\u200b","","313,561"],["Other liabilities","\u200b","","59,884","\u200b","","(42,615)","\u200b","","17,269"],["Deferred income taxes","\u200b","","113","\u200b","","\u2014","\u200b","","113"],["Common stock","\u200b","","1","\u200b","","\u2014","\u200b","","1"],["Additional paid-in capital","\u200b","","552,923","\u200b","","\u2014","\u200b","","552,923"],["Retained deficit","\u200b","","(775,937)","\u200b","","27,501","\u200b","","(748,436)"],["Treasury stock, at cost","\u200b","","(24,167)","\u200b","","\u2014","\u200b","","(24,167)"],["Total shareholders\u2019 deficit","\u200b","","(247,180)","\u200b","","27,501","\u200b","","(219,679)"],["Total liabilities and shareholders\u2019 deficit","\u200b","$","1,193,207","\u200b","$","(315,701)","\u200b","$","877,506"]]
[[/GREPCENT_TABLE]]

​

52

Table of Contents

Below is Consolidating Statement of Operations information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Consolidated Statement of Operations for the year ended December 31, 2021 (in thousands):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","\u200b","Consolidated","\u200b","\u200b","Eliminations of Unrestricted Subsidiaries","\u200b","\u200b","Consolidated restricted subsidiaries"],["Revenues:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Oil","\u200b","$","329,557","\u200b","$","(463)","\u200b","$","329,094"],["NGLs","\u200b","","44,343","\u200b","","(21,438)","\u200b","","22,905"],["Natural gas","\u200b","","173,749","\u200b","","(92,863)","\u200b","","80,886"],["Other","\u200b","","10,361","\u200b","","(4,786)","\u200b","","5,575"],["Total revenues","\u200b","","558,010","\u200b","","(119,550)","\u200b","","438,460"],["Operating expenses:","\u200b","","","\u200b","","","\u200b"],["Lease operating expenses","\u200b","","174,582","\u200b","","(26,507)","\u200b","","148,075"],["Production taxes","\u200b","","10,074","\u200b","","(6,620)","\u200b","","3,454"],["Gathering and transportation","\u200b","","17,845","\u200b","","(2,539)","\u200b","","15,306"],["Depreciation, depletion, amortization and accretion","\u200b","","113,447","\u200b","","3,579","\u200b","","117,026"],["General and administrative expenses","\u200b","","52,400","\u200b","","(647)","\u200b","","51,753"],["Total operating expenses","\u200b","","368,348","\u200b","","(32,735)","\u200b","","335,613"],["Operating (loss) income","\u200b","","189,662","\u200b","","(86,814)","\u200b","","102,848"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Interest expense, net","\u200b","","70,049","\u200b","","(9,782)","\u200b","","60,267"],["Derivative loss (gain)","\u200b","","175,313","\u200b","","(104,533)","\u200b","","70,780"],["Gain on debt transactions","\u200b","","\u2014","\u200b","","\u2014","\u200b","","\u2014"],["Other expense, net","\u200b","","(6,165)","\u200b","","\u2014","\u200b","","(6,165)"],["(Loss) income before income taxes","\u200b","","(49,535)","\u200b","","27,501","\u200b","","(22,034)"],["Income tax benefit","\u200b","","(8,057)","\u200b","","\u2014","\u200b","","(8,057)"],["Net (loss) income","\u200b","$","(41,478)","\u200b","$","27,501","\u200b","$","(13,977)"]]
[[/GREPCENT_TABLE]]

​

The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Mobile Bay Properties for the period from May 19, 2021 through December 31, 2021:

​

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b"],["\u200b","\u200b","For the period from May 19, 2021 to December 21, 2021"],["Production Volumes:"],["Oil (MBbls)","","13"],["NGLs (MBbls)","","603"],["Natural gas (MMcf)","","20,417"],["Total oil equivalent (MBoe)","","4,019"],["Average realized sales prices:","\u200b"],["Oil ($/Bbl)","$","35.64"],["NGLs ($/Bbl)","","35.55"],["Natural gas ($/Mcf)","","4.55"],["Oil equivalent ($/Boe)","","28.56"],["Average production costs(1):","\u200b","\u200b"],["Oil equivalent ($/Boe)","$","7.23"]]
[[/GREPCENT_TABLE]]

​

[[GREPCENT_TABLE]]
[["","(1)","Includes lease operating expenses and gathering and transportation costs."]]
[[/GREPCENT_TABLE]]

Reserves information is for the Mobile Bay properties is described in more detail under Part I Item 2, Properties, in this Form 10-K.

53

Table of Contents

Insurance Coverage

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. The current policy is effective for one year beginning June 1, 2021 and limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements. With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering all of our higher valued properties, and $150.0 million for all other properties subject to a retention of $17.5 million on the conventional shelf properties and $12.5 million on the deepwater properties. Included within the $162.5 million aggregate limit is TLO coverage on our Mahogany platform, which has no retention. The operational and named windstorm coverages are effective for one year beginning June 1, 2021. Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy.

Our general and excess liability policies are effective for one year beginning May 1, 2021 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility requirement under the OPA of 1990, we are required to evidence $35.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount. We do not carry business interruption insurance.

The premiums for the above policies including brokerage fees were $9.7 million for the May/June 2021 policy renewals compared to $10.9 million for the expiring policies. The change in our premiums effective with the May/June 2020 renewal was primarily attributable to negotiations.

Contractual Obligations

At December 31, 2021, we did not have any financing leases. The following table summarizes our significant contractual obligations by maturity as of December 31, 2021 (in millions):

​

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Payments Due by Period as of December 31, 2021"],["\u200b","","\u200b","","\u200b","","One to","","\u200b","","\u200b"],["\u200b","\u200b","\u200b","\u200b","","Less than","","Three","","Three to","","More Than"],["\u200b","\u200b","Total","\u200b","One Year","","Years","\u200b","Five Years","\u200b","Five Years"],["Long-term debt \u2013 principal","\u200b","$","743.3","\u200b","$","43.0","\u200b","$","616.3","\u200b","$","53.0","\u200b","$","31.0"],["Long-term debt \u2013 interest (1)","\u200b","","138.0","\u200b","","66.5","\u200b","","61.4","\u200b","","8.4","\u200b","","1.7"],["Operating leases","\u200b","","23.8","\u200b","","1.1","\u200b","","3.7","\u200b","","3.1","\u200b","","15.9"],["Asset retirement obligations (2)","\u200b","","424.5","\u200b","","56.4","\u200b","","83.1","\u200b","","82.4","\u200b","","202.6"],["Other liabilities and commitments (3)","\u200b","","86.8","\u200b","","9.1","\u200b","","14.3","\u200b","","12.1","\u200b","","51.3"],["Total","\u200b","$","1,416.4","\u200b","$","176.1","\u200b","$","778.8","\u200b","$","159.0","\u200b","$","302.5"]]
[[/GREPCENT_TABLE]]

​

[[GREPCENT_TABLE]]
[["","(1)","Interest payments were calculated through the stated maturity date of the related debt:"]]
[[/GREPCENT_TABLE]]

(a) Interest payments for the Credit Agreement were calculated using the interest rate applied to our outstanding balance as of December 31, 2021 and assumes no change in this interest rate in future periods. In addition, a commitment fee of 3.0% was applied on the available balance as of December 31, 2021 and fees related to letters of credit were estimated at the rate incurred on December 31, 2021.

(b) Interest payments on the Senior Second Lien Notes were calculated per the terms of the notes;

(c) Interest payments on the Term Loan were calculated at the 7% interest rate set forth in the Term Loan.

​

[[GREPCENT_TABLE]]
[["","(2)","ARO in the above table is presented on a discounted basis, consistent with the amounts reported on the Consolidated Balance Sheet as of December 31, 2021 and are estimates of future payments. Actual payments and the timing of the payments may be significantly different than our estimates. All other amounts in the above table are presented on an undiscounted basis."]]
[[/GREPCENT_TABLE]]

54

Table of Contents

​

[[GREPCENT_TABLE]]