WHITING PETROLEUM Unless the context otherwise requires, the terms "Whiting," "we," "us," "our" or "ours" when used in this Item refer toWhiting Petroleum Corporation , together with its consolidated subsidiaries,Whiting Oil and Gas Corporation ("Whiting Oil and Gas" or "WOG"),Whiting US Holding Company ,Whiting Canadian Holding Company ULC ,Whiting Resources LLC ("WRC," formerlyWhiting Resources Corporation ) andWhiting Programs, Inc. InSeptember 2020 ,Whiting US Holding Company merged with and into WOG with WOG surviving, and WRC transferred all of its operating assets to WOG. InNovember 2020 , WRC, over a series of steps, was amalgamated withWhiting Canadian Holding Company ULC and subsequently dissolved. When the context requires, we refer to these entities separately.
This document contains forward-looking statements, which give our current expectations or forecasts of future events. Please refer to "Forward-Looking Statements" at the end of this Item for an explanation of these types of statements.
Overview
We are an independent oil and gas company engaged in development, production and acquisition activities primarily in theRocky Mountains region ofthe United States where we are focused on developing our large resource play in theWilliston Basin ofNorth Dakota andMontana . Since our inception, we have built a strong asset base through a combination of property acquisitions, development of proved reserves and exploration activities. We are currently focusing our capital programs on drilling and workover opportunities that we believe provide attractive well-level returns in order to maintain consistent production levels and generate free cash flow. In addition, we are selectively pursuing acquisitions that complement our existing core properties. During 2021, we focused on high-return projects in our asset portfolio that generated significant cash flow from operations. We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own. Refer to "Recent Developments" below for more information on our recent acquisition and divestiture activity. We are committed to developing the energy resources the world needs in a safe and responsible way that allows us to protect our employees, our contractors, our vendors, the public and the environment while also meeting or exceeding regulatory requirements. We continually evolve our practices to better protect wildlife habitats and communities, to reduce freshwater use in our development process, to identify and reduce methane emissions of our operations, to encourage waste reduction programs and to promote worker safety. Additionally, we are committed to transparency in reporting our environmental, social and governance performance and to monitoring such performance through various measures, some of which are tied to our short-term incentive program for all employees. Refer to our Sustainability Report published on our website for sustainability performance highlights and additional information. Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Concurrently, our oil and gas development and production operations are subject to stringent environmental regulations governing the release of certain materials into the environment which often require costly compliance measures that carry substantial penalties for noncompliance. However, we have not incurred any material penalties historically. Refer to "Government Regulation" in Item 1 of this Annual Report on Form 10-K for more information. Our revenue, profitability, cash flows and future growth rate depend on many factors which are beyond our control, such as oil and gas prices, economic, political and regulatory developments, the financial condition of our industry partners, competition from other sources of energy, cost pressures as a result of inflation and the other items discussed under the caption "Risk Factors" in Item 1A of this Annual Report on Form 10-K. Oil and gas prices historically have been volatile and may fluctuate widely in the future. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas prices since the first quarter of 2019: 2019 2020 2021 Q1 Q2 Q3 Q4 Q1 Q2
Q3 Q4 Q1 Q2 Q3 Q4
Crude oil
Oil prices improved during 2021 compared to the lows experienced during 2020, when prices were depressed primarily due to the economic effects of the coronavirus pandemic on the demand for oil and natural gas and uncertainty around output restraints on oil production agreed upon by theOrganization of Petroleum Exporting Countries ("OPEC") and other oil exporting nations. While oil, NGL and natural gas prices have recovered significantly, uncertainties related to the demand for oil and natural gas products remain as the pandemic continues to impact the world economy andOPEC continues to debate appropriate production levels to balance the market. Lower oil, NGL and natural gas prices decrease our revenues and reduce the amount of oil and natural gas that we can produce economically, which decreases our oil and gas reserve quantities. Substantial and extended declines in oil, NGL and natural gas prices have resulted, and may result, in impairments of our proved oil and gas properties or undeveloped acreage (such as the impairments discussed below under "Results of Operations") and may materially and adversely affect our future business, financial condition, cash 49 Table of Contents
flows, results of operations, liquidity or ability to fund planned capital expenditures. In addition, lower commodity prices may result in a reduction of the borrowing base under our Credit Agreement, which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our Credit Agreement. Alternatively, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives (such as the net derivative losses discussed below under "Results of Operations"). For a discussion of material changes to our proved reserves fromDecember 31, 2020 toDecember 31, 2021 and our ability to convert PUDs to proved developed reserves, refer to "Reserves" in Item 2 of this Annual Report on Form 10-K.
Additionally, for a discussion relating to the minimum remaining terms of our leases, refer to "Acreage" in Item 2 of this Annual Report on Form 10-K.
Recent Developments
Return of Capital. InFebruary 2022 , we announced an initial regular dividend payment of$0.25 per share which will begin in the first quarter of 2022. Our Board and management are committed to returning capital in line with our industry peers and we will continue to evaluate all forms of capital returns, including buying back outstanding shares and paying variable dividends.Williston Basin Acquisitions. OnSeptember 14, 2021 , we completed the acquisition of interests in oil and gas properties located inMountrail County, North Dakota for an aggregate purchase price of$271 million (before closing adjustments). This transaction was funded primarily with borrowings under our Credit Agreement, which have subsequently been repaid.
On
OnFebruary 1, 2022 , we entered into a purchase and sale agreement to acquire additional interests in oil and gas properties located inMountrail County, North Dakota for an aggregate purchase price of$240 million (before closing adjustments). We expect this transaction to close inMarch 2022 . We intend to finance this acquisition with cash on hand and borrowings under our Credit Agreement. On a combined basis, our recentWilliston Basin acquisitions included interests in 76 new gross producing oil and gas wells and increased interests in 527 existing gross producing wells. Overall, the acquisitions effectively added 136.2 net producing wells and included approximately 23,300 net undeveloped acres. Denver-Julesburg Basin Divestiture. OnSeptember 23, 2021 , we completed the divestiture of all of our interests in producing assets and undeveloped acreage, including the associated midstream assets, of our Redtail field located in theDenver-Julesburg Basin ofWeld County, Colorado for aggregate sales proceeds of$171 million (before closing adjustments). The divestiture remains subject to a final settlement between Whiting and the buyer of the properties. The production from the divested properties (which was approximately 51% oil) represented approximately 8% of our average total production as of the divestiture date. We used the net proceeds from the sale to repay a portion of the borrowings outstanding under our Credit Agreement. Chapter 11 Emergence and Fresh Start Accounting. OnApril 1, 2020 (the "Petition Date"), Whiting and certain of its subsidiaries (the "Debtors") commenced voluntary cases (the "Chapter 11 Cases") under chapter 11 of the Bankruptcy Code. OnJune 30, 2020 , the Debtors filed the Joint Chapter 11 Plan of Reorganization ofWhiting Petroleum Corporation and its Debtor affiliates (as amended, modified and supplemented, the "Plan"). OnAugust 14, 2020 , theBankruptcy Court confirmed the Plan. OnSeptember 1, 2020 (the "Emergence Date"), the Debtors satisfied all conditions required for Plan effectiveness and emerged from the Chapter 11 Cases. Beginning on the Emergence Date, we applied fresh start accounting, which resulted in a new basis of accounting and we became a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements afterSeptember 1, 2020 are not comparable with the consolidated financial statements on or prior to that date and the historical financial statements on or before the Emergence Date are not a reliable indicator of our financial condition and results of operations for any period after the adoption of fresh start accounting. References to "Successor" refer to Whiting and its financial position and results of operations after the Emergence Date. References to "Predecessor" refer to Whiting and its financial position and results of operations on or before the Emergence Date. References to "2020 Successor Period" relate to the period ofSeptember 1, 2020 throughDecember 31, 2020 . References to "2020 Predecessor Period" relate to the period ofJanuary 1, 2020 throughAugust 31, 2020 . Although GAAP requires that we report on our results for the 2020 Successor Period and the 2020 Predecessor Period separately, in certain circumstances management views our combined Predecessor and Successor operating results for the year endedDecember 31, 2020 as the most meaningful comparisons to current and prior periods. Accordingly, references to "2020 Combined YTD Period" refer to the year endedDecember 31, 2020 . 50
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Settlement of Bankruptcy Claims. Prior to the Chapter 11 Cases, WOG was party to various executory contracts withBNN Western, LLC , subsequently renamedTallgrass Water Western, LLC ("Tallgrass"), including a Produced Water Gathering and Disposal Agreement (the "PWA"). InJanuary 2021 , WOG and Tallgrass entered into a settlement agreement to resolve all of the related claims before theBankruptcy Court relating to such executory contracts, terminated the PWA and entered into a newWater Transport , Gathering and Disposal Agreement. In accordance with the settlement agreement, we made a$2 million cash payment and issued 948,897 shares of the Successor's common stock pursuant to the confirmed Plan to a Tallgrass entity inFebruary 2021 .
2021 Highlights and Future Considerations
Operational Highlights
Our properties in theWilliston Basin ofNorth Dakota andMontana target the Bakken andThree Forks formations. Net production fromNorth Dakota andMontana averaged 91.6 MBOE/d for the fourth quarter of 2021, representing an 8% increase from the third quarter of 2021. Across our acreage in theWilliston Basin , we have implemented completion designs specifically tailored to unique reservoir conditions to increase well performance while reducing cost. We continued to focus on reducing time-on-location and total well cost while maximizing our lateral footage through drilling best practices including utilizing top tier drilling rigs, advanced downhole motor and drill bit technology and our custom drilling fluid system.
During the year ended
During the majority of 2021, we had one active completion crew in theWilliston Basin . In addition, we resumed drilling in the area in February with one rig and added a second rig at the end of September. During the fourth quarter of 2021, we drilled 17 gross (10.4 net) operated wells and TIL 16 gross (12.0 net) operated wells in this area. As ofDecember 31, 2021 , we have 34 gross (20.2 net) operated drilled uncompleted wells. Under our current 2022 capital program, we expect to TIL approximately 68 gross (43.4 net) operated wells
in this area during the year. OtherNon-Core Properties
Upon termination, the NPI in the underlying properties, which received 90% of the net cash proceeds from the sale of oil and natural gas production from the underlying properties prior to its termination, reverted to Whiting. As ofDecember 31, 2021 , the NPI included interests in 1,305 gross (364.4 net) producing wells. The incremental production from the underlying properties that reverted to Whiting upon termination was approximately 2.0 MBOE/d based on production during the fourth quarter of 2021. The incremental LOE expense that reverted to Whiting upon termination was approximately$2 million . The asset retirement obligations for these properties were not conveyed to Trust II and have therefore been included in our consolidated financial statements for all periods presented. Additionally, the reserves disclosed in this Annual Report on Form 10-K contemplate the reversion of the NPI onDecember 31, 2021 .
Financing Highlights
On the Emergence Date, in connection with our emergence from the Chapter 11 Cases, we repaid all outstanding borrowings and accrued interest on the Predecessor's credit agreement (the "Predecessor Credit Agreement") and entered into the Credit Agreement with a syndicate of banks. InSeptember 2021 , the borrowing base under the Credit Agreement of$750 million was reaffirmed in connection with our semi-annual borrowing base redetermination. OnSeptember 15, 2021 , we amended the Credit Agreement to reduce the amount of future production we are required to hedge. In accordance with the amendment, we are now only required to hedge 50% of our projected production for any succeeding twelve months, as compared to 65% prior to the amendment. Additionally, as long as we maintain a net leverage ratio of less than 1.0 to 1.0, we are no longer required to hedge any production for a second succeeding twelve months, compared to a 35% requirement prior to the amendment. Refer to the "Long-Term Debt" footnote in the notes to the consolidated financial statements for more information. 51
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2022 Exploration and Development Budget
Our 2022 exploration and development ("E&D") budget is a range of $360 million
to $400 million , which we expect to fund with net cash provided by our operating
activities and cash on hand, and represents an increase from the $247 million
incurred on E&D expenditures during 2021. This increase in spending is
primarily attributable to increased working interests related to wells we plan
to drill on the acreage acquired through our recent Williston Basin acquisitions
as further described in "Recent Developments" above, fewer drilled uncompleted
wells as of the end of 2021 as compared to the prior year and inflationary cost
pressures on services and materials. The 2022 budget reinvests approximately
40% of our expected EBITDA for the year, which we expect to allow us to maintain
our recently announced dividend and continue to increase our return of capital.
We continue to maintain our commitment to keep our capital spending within cash
flows generated from operations and strict adherence to economic full cycle well
returns. To the extent net cash provided by operating activities is higher or
lower than currently anticipated, we would generate more or less free cash flow
than we currently anticipate and may adjust our E&D budget or adjust borrowings
outstanding under the Credit Agreement. We believe our 2022 E&D plan provides
the opportunity for the highest return and most efficient use of our capital on
our existing development opportunities.
Dakota Access Pipeline
OnMarch 25, 2020 , theU.S. District Court for D.C . ("D.C. District Court ") found that theU.S. Army Corps of Engineers ("Army Corps ") had violated the National Environmental Policy Act when it granted an easement relating to a portion of the Dakota Access Pipeline ("DAPL") because it had failed to prepare an environmental impact statement ("EIS"). As a result, in an order issuedJuly 6, 2020 , theD.C. District Court vacated the easement and directed that the DAPL be shut down and emptied of oil byAugust 5, 2020 . After issuing a stay of the order to shut down the pipeline onAugust 5, 2020 , theU.S. Court of Appeals for the D.C. Circuit ("D.C. Appellate Court"), onJanuary 26, 2021 , affirmed theD.C. District Court's decision to vacate the easement and concluded that theD.C. District Court must further consider whether shut down of the DAPL is an appropriate remedy while theArmy Corps develops an EIS. OnMay 21, 2021 , theD.C. District Court ruled that it would not issue an injunction requiring a shutdown of the DAPL and that the DAPL could continue to operate while theArmy Corps prepares an EIS.The D.C. District Court further ruled onJune 22, 2021 that the litigation be dismissed and that the plaintiffs could renew their challenge to DAPL upon theArmy Corps' issuance of an EIS. Barring different discretionary action by theArmy Corps , these rulings allow the DAPL's continued operation unless and until new challenges are made and succeed following issuance of the EIS, which theArmy Corps anticipates issuing in the fall of 2022. OnSeptember 20, 2021 , the DAPL's owner filed a petition with theU.S. Supreme Court seeking review of the lower courts' decisions requiring a new EIS and permit, and the plaintiff tribes andArmy Corps filed briefs opposing such review. However, theU.S. Supreme Court declined to accept the case for review. The potential disruption of transportation as a result of the DAPL being shut down or the anticipation of the DAPL being shut down could negatively impact our ability to achieve the most favorable prices for our crude oil production, which could have an adverse effect on our business, financial condition, results of operations and cash flows. To help mitigate the potential impact of an unfavorable outcome, we have coordinated with our midstream partners and downstream markets to source transportation alternatives. 52 Table of Contents Results of Operations We cannot adequately benchmark certain operating results of the 2020 Successor Period against any of the previous periods reported in our consolidated financial statements without combining that period with the 2020 Predecessor Period, and we do not believe that reviewing the results of this period in isolation would be useful in identifying trends in or reaching conclusions regarding our overall operating performance. Management believes that our key performance metrics such as sales, production, lease operating expenses and general and administrative expenses for the 2020 Successor Period when combined with the 2020 Predecessor Period provide more meaningful comparisons to current and prior periods and are more useful in identifying current business trends.
Accordingly, in addition to presenting our results of operations as reported in
our consolidated financial statements in accordance with GAAP, in certain
circumstances the discussion in "Results of Operations" below utilizes the
combined results for the year ended
Successor Predecessor Non-GAAP
Combined Year
Year Ended Eight Months Ended
December 31, Four Months Ended Ended August 31, December 31,
2021 December 31, 2020 2020 2020
Net production
Oil (MMBbl) 19.3 6.8 15.3 22.1
NGLs (MMBbl) 7.2 2.1 4.5 6.6
Natural gas (Bcf) 42.0 14.3 29.7 44.0
Total production (MMBOE) 33.5 11.4 24.7 36.1
Net sales (in millions) (1)
Oil $ 1,251.0 $ 254.1 $ 440.8 $ 694.9
NGLs 162.6 12.4 20.1 32.5
Natural gas 98.2 6.9 (1.9) 5.0
Total oil, NGL and natural gas
sales $ 1,511.8 $ 273.4 $ 459.0 $ 732.4
Average sales prices
Oil (per Bbl) (1) $ 64.77 $ 37.05 $ 28.86 $ 31.40
Effect of oil hedges on average
price (per Bbl) (14.70) (0.34) 3.00 1.96
Oil after the effect of hedging
(per Bbl) $ 50.07 $ 36.71 $ 31.86 $ 33.36
Weighted average NYMEX price (per
Bbl) (2) $ 67.86 $ 41.84 $ 38.23 $ 39.35
NGLs (per Bbl) (1) $ 22.53 $ 5.90 $ 4.45 $ 4.91
Effect of NGL hedges on average
price (per Bbl) (1.19) - - -
NGLs after the effect of hedging
(per Bbl) $ 21.34 $ 5.90 $ 4.45 $ 4.91
Natural gas (per Mcf) (1) $ 2.34 $ 0.48 $ (0.06) $ 0.11
Effect of natural gas hedges on
average price (per Mcf) (0.74) (0.11) (0.01) (0.04)
Natural gas after the effect of
hedging (per Mcf) $ 1.60 $ 0.37 $ (0.07) $ 0.07
Weighted average NYMEX price (per
MMBtu) (2) $ 3.59 $ 2.44 $ 1.76 $ 1.98
Costs and expenses (per BOE)
Lease operating expenses $ 7.23 $ 6.52 $ 6.40 $ 6.43
Transportation, gathering,
compression and other $ 0.90 $ 0.71 $ 0.90 $ 0.84 Production and ad valorem taxes $ 3.29 $ 2.13
$ 1.67 $ 1.81
Depreciation, depletion and
amortization $ 6.16 $ 6.83 $ 13.69 $ 11.53
General and administrative $ 1.48 $ 1.91 $ 3.71 $ 3.15 (1) Before consideration of hedging transactions.
(2) Average NYMEX pricing weighted for monthly production volumes.
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2021 Compared to 2020 Successor Period and 2020 Predecessor Period or 2020 Combined YTD Period
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased$779 million to$1.5 billion when comparing 2021 to the 2020 Combined YTD Period. Changes in sales revenue between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging). When comparing 2021 to the 2020 Combined YTD Period, increases in commodity prices realized between periods accounted for an$865 million increase in revenue, which was partially offset by a decrease in total production between periods that accounted for an$86 million decrease in revenue. Our oil and gas volumes decreased by 13% and 5%, respectively, while our NGL volumes increased by 9% between periods. The volume decreases between periods were primarily driven by normal field production decline and reduced development activity in 2020 as a result of sustained lower commodity prices and our bankruptcy filing, both of which negatively impacted production during 2021. The decline in production resulting from lower activity was partially offset by production from new wells drilled and completed in theWilliston Basin during 2021 as well as higher NGL yields. Our average price for oil, NGLs and natural gas (before the effects of hedging) increased 106%, 359% and 2,027%, respectively, between periods. Our average realized price for oil, NGLs and natural gas primarily increased as a result of favorable movements in benchmark indices between periods. Our oil average realized price differentials to NYMEX improved between periods as a result of decreased basin-wide utilization of pipeline capacity and lower firm transportation costs during 2021, and our natural gas average realized price differentials to NYMEX also improved significantly as a result of stronger regional pricing in theWilliston Basin during 2021. During the 2020 Combined YTD Period, our average sales price realized for NGLs and natural gas was negatively impacted by rising market differentials as compared to market indices as well as high fixed third-party costs for transportation, gathering and compression services. These third-party costs sometimes exceeded the ultimate price we received for our natural gas and accordingly resulted in negative gas revenues during the 2020 Predecessor Period. While these negative gas prices adversely affected our total revenues, we continued to produce our wells in order to sell the associated oil and NGLs from these wells and to meet lease and regulatory requirements. Lease Operating Expenses. Our lease operating expenses ("LOE") during 2021 were$242 million , a$10 million increase over the 2020 Combined YTD Period. This increase was primarily due to a$16 million increase in well workover costs and a$7 million increase in the cost of oil field goods and services due to increased completion activity, partially offset by a$9 million decrease in saltwater disposal costs due to lower produced volumes between periods and a$5 million decrease due to increased utilization of company-owned equipment.
Our lease operating expenses on a BOE basis increased when comparing 2021 to the
2020 Combined YTD Period. LOE per BOE amounted to
Transportation, Gathering, Compression and Other. Our transportation,
gathering, compression and other ("TGC") expenses during 2021 were
TGC per BOE, however, increased when comparing 2021 to the 2020 Combined YTD Period. TGC per BOE amounted to$0.90 per BOE during 2021, which represents an increase of$0.06 per BOE (or 7%) from the 2020 Combined YTD Period. This increase was mainly due to the transportation of certain oil volumes to additional delivery points during the second half of 2021, partially offset by decreased rates negotiated with midstream partners as a result of the Chapter 11 Cases. Production and Ad Valorem Taxes. Our production and ad valorem taxes during 2021 were$110 million , a$45 million increase over the 2020 Combined YTD Period, which was primarily due to higher sales revenue between periods. Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was 7.0% and 8.5% for 2021 and the 2020 Combined YTD Period, respectively. Our production tax rate for 2021 was lower than the rate for the 2020 Combined YTD Period as certain production taxes levied on unprocessed gas are volume-based and did not increase with the increase in realized prices. Additionally, we recognizedColorado severance tax refunds during 2021. 54 Table of Contents Depreciation, Depletion and Amortization. The components of our depletion, depreciation and amortization ("DD&A") expense were as follows (in thousands): Successor Predecessor Non-GAAP Year Ended Eight Months Combined Year December 31, Four Months Ended Ended August 31, Ended 2021 December 31, 2020 2020 December 31, 2020 Depletion$ 193,529 $ 71,901 $ 327,227 $ 399,128 Accretion of asset retirement obligations 8,237
3,801 8,200 12,001 Depreciation 4,709 1,800 3,330 5,130 Total$ 206,475 $ 77,502 $ 338,757 $ 416,259
DD&A decreased between 2021 and the 2020 Combined YTD Period primarily due to$206 million in lower depletion expense related to a lower depletion rate between periods. On a BOE basis, our overall DD&A rate of$6.16 per BOE for 2021 was 10% lower than the rate of$6.83 for the 2020 Successor Period and 55% lower than the rate of$13.69 per BOE for the 2020 Predecessor Period. The primary factors contributing to the lower DD&A rates during the Successor periods were impairment write-downs on proved oil and gas properties in theWilliston Basin recognized in the first and second quarters of 2020 and the application of fresh start accounting upon emergence from the Chapter 11 Cases, under which we adjusted the value of our oil and gas properties down to their fair values on the Emergence Date. Refer to the "Fresh Start Accounting" footnote in the notes to the consolidated financial statements for more information. Also contributing to the lower DD&A rate in 2021 were upward reserve revisions to proved reserves, which were largely driven by higher commodity prices during the period.
Exploration and Impairment Costs. The components of our exploration and impairment expense were as follows (in thousands):
Successor Predecessor Non-GAAP
Combined Year
Year Ended Eight Months Ended
December 31, Four Months Ended Ended August 31, December 31,
2021 December 31, 2020 2020 2020
Impairment $ 6,707 $ 3,233 $ 4,161,885 $ 4,165,118
Exploration 4,074 4,632 22,945 27,577
Total $ 10,781 $ 7,865 $ 4,184,830 $ 4,192,695
Impairment expense for both of the Successor periods primarily relates to the
amortization of leasehold costs associated with individually insignificant
unproved properties. Impairment expense for the 2020 Predecessor Period
primarily related to (i) $4 billion in non-cash impairment charges for the
partial write-down of proved oil and gas properties across our Williston Basin
resource play due to a reduction in reserves driven by depressed oil prices and
a resultant decline in future development plans for those properties at the time
and (ii) $12 million in impairment write-downs of undeveloped acreage costs for
leases where we no longer had plans to drill.
Exploration costs decreased $24 million during 2021 compared to the 2020
Combined YTD Period primarily due to $17 million of lower deficiency fees paid
under our produced water disposal agreement at our Redtail field, which contract
was rejected through the Chapter 11 Cases, and $3 million of lower
geology-related general and administrative expenses due to a company
restructuring in September 2020 . Additionally, the 2020 Combined YTD Period
includes $4 million of charges related to the write-off of certain suspended
well costs for wells we no longer intend to drill and early rig termination
fees
incurred during the period.
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General and Administrative Expenses. We report general and administrative ("G&A") expenses net of third-party reimbursements and internal allocations.
The components of our G&A expenses were as follows (in thousands):
Successor Predecessor Non-GAAP
Four Months
Year Ended Ended Eight Months Combined Year
December 31, December 31, Ended August 31, Ended
2021 2020 2020 December 31, 2020
General and administrative expenses,
other (1) $ 111,171 $ 43,853 $ 135,746 $ 179,599
Stock-based compensation, non-cash 10,745 515 4,188 4,703
Reimbursements and allocations (72,396) (22,634) (48,118) (70,752)
General and administrative expenses,
net (GAAP) 49,520 21,734 91,816 113,550
Less: Significant cost drivers (2) - (12,359) (32,888) (45,247)
Non-GAAP general and administrative
expenses less significant cost
drivers (3) $ 49,520 $ 9,375$ 58,928 $ 68,303
General and administrative expenses, other excludes non-cash stock-based (1) compensation expense and reimbursements and allocations. We believe general
and administrative expenses, other provides useful information to compare our
expenses between periods without the impact of the aforementioned items.
Includes severance and restructuring charges, cash retention incentives for (2) Predecessor executives and directors and third-party advisory and legal fees
related to the Chapter 11 Cases and charges related to litigation and
bankruptcy claim settlements discussed below.
We believe non-GAAP general and administrative expenses less significant cost
drivers is a useful measure for investors to understand our general and
administrative expenses incurred on a recurring basis. We further believe (3) investors may utilize this non-GAAP measure to estimate future general and
administrative expenses. However, this non-GAAP measure is not a substitute
for general and administrative expenses, net (GAAP), and there can be no
assurance that any of the significant cost drivers excluded from such metric
will not be incurred again in the future.
G&A expenses, other during 2021 decreased$68 million compared to the 2020 Combined YTD Period primarily due to$45 million of significant cost drivers incurred during the 2020 Combined YTD Period, including (i)$22 million in cash retention incentives paid to Predecessor executives and directors, (ii)$11 million of third party advisory and legal fees related to the Chapter 11 Cases that were incurred prior to the Petition Date or after the Emergence Date, (iii)$8 million of severance and restructuring costs for a company restructuring completed in the third quarter of 2020 and (iv)$5 million of additional costs related to litigation and bankruptcy settlements. In addition, compensation costs decreased by$17 million and corporate overhead costs decreased by$9 million as a result of the aforementioned company restructuring in the third quarter of 2020 and other cost reduction strategies implemented upon emergence from the Chapter 11 Cases, including the renegotiation of certain contracts. G&A expense per BOE amounted to$1.48 during 2021, which represents a decrease of$1.67 per BOE (or 53%) from the 2020 Combined YTD Period. This decrease was mainly due to the overall decrease in G&A discussed above partially offset by lower overall production volumes between periods. Derivative (Gain) Loss, Net. Our commodity derivative contracts are marked to market each reporting period with fair value gains and losses recognized immediately in earnings as derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under these contracts result in us making or receiving a payment to or from the counterparty. Derivative (gain) loss, net, amounted to a loss of$520 million and a gain of$157 million for 2021 and the 2020 Combined YTD Period, respectively. These gains and losses relate to our collar, swap, basis swap and differential swap commodity derivative contracts and resulted from the upward and downward shifts, respectively, in the futures curve of forecasted commodity prices for crude oil, natural gas and NGLs during those periods.
For more information on our outstanding derivatives refer to the "Derivative Financial Instruments" footnote in the notes to the consolidated financial statements.
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(Gain) Loss on Sale of Properties. During 2021, we sold all of our interests in
the producing assets and undeveloped acreage, including the associated midstream
assets, of our Redtail field located in the Denver-Julesburg Basin of Weld
County, Colorado for aggregate sales proceeds of $171 million , which resulted in
a pre-tax gain on sale of $86 million . The divestiture remains subject to a
final settlement between Whiting and the buyer of the properties. Refer to the
"Acquisitions and Divestitures" footnote in the consolidated financial
statements for more information on this transaction. Additionally, during 2021,
a series of non-core producing oil and gas properties were divested for
aggregate sales proceeds of $7.4 million (before closing adjustments). As a
result of one of these divestitures, our asset retirement obligation liability
decreased by $10 million and we recognized a corresponding gain on sale of $10
million .
Interest Expense. The components of our interest expense were as follows (in
thousands):
Successor Predecessor Non-GAAP
Combined Year
Year Ended Eight Months Ended
December 31, Four Months Ended Ended August 31, December 31,
2021 December 31, 2020 2020 2020
Credit agreements $ 11,155 $ 6,570 $ 23,948 $ 30,518
Amortization of debt issue costs,
discounts and premiums 3,554 1,257 13,536 14,793
Other 1,672 253 730 983
Notes - - 34,840 34,840
Total $ 16,381 $ 8,080 $ 73,054 $ 81,134 The decrease in interest expense of$65 million during 2021 compared to the 2020 Combined YTD Period was primarily attributable to lower interest costs incurred on our notes and our credit agreements as well as lower amortization of debt issue costs, discounts and premiums. Upon filing of the Chapter 11 Cases onApril 1, 2020 , we stopped incurring interest on our notes, which resulted in a$35 million decrease in note interest expense between periods. In addition, the remaining unamortized debt issuance costs and premiums associated with these notes were written off on the Petition Date, resulting in an$11 million decrease in amortization expense between periods. Upon emergence from the Chapter 11 Cases, all outstanding obligations under our notes were cancelled in exchange for shares of Successor common stock. Refer to the "Chapter 11 Emergence" and "Long-Term Debt" footnotes in the notes to the consolidated financial statements for more information. The decrease in interest expense incurred on our credit agreements of$19 million during 2021 compared to the 2020 Combined YTD Period resulted from lower borrowings outstanding between periods. Our weighted average borrowings outstanding under the Credit Agreement during 2021 were$189 million compared to$644 million of weighted average borrowings outstanding under the applicable Credit Agreements during the 2020 Combined YTD Period. Our weighted average debt outstanding during 2021, consisting solely of borrowings under the Credit Agreement, carried a weighted average cash interest rate of 5.9%. Our weighted average debt outstanding during the 2020 Predecessor Period, consisting of the notes and borrowings outstanding on the Predecessor Credit Agreement, was$3.2 billion , with a weighted average cash interest rate of 2.8%. The lower interest rate during the 2020 Predecessor Period primarily relates to the discontinuation of interest on our senior notes beginning inApril 2020 as a result of filing the Chapter 11 Cases. Subsequent to our emergence from bankruptcy, our weighted average borrowings outstanding during the 2020 Successor Period were$410 million , with a weighted average cash interest rate of 4.8%. Gain on Extinguishment of Debt. During the 2020 Predecessor Period, we paid$53 million to repurchase$73 million aggregate principal amount of our convertible senior notes and recognized a$23 million gain on extinguishment of debt. Refer to the "Long-Term Debt" footnote in the notes to consolidated financial statements for more information on this repurchase. Additionally, inMarch 2020 , the holders of$3 million aggregate principal amount of our convertible senior notes elected to convert. Upon conversion, such holders of the converted convertible senior notes were entitled to receive an insignificant cash payment onApril 1, 2020 , which we did not pay in conjunction with the filing of the Chapter 11 Cases. As a result of such conversion we recognized a$3 million gain on extinguishment of debt during the 2020 Predecessor Period. 57
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Reorganization Items, Net. During the 2020 Predecessor Period, we recognized a net gain of$217 million related to the Chapter 11 Cases consisting of (i) gains on settlement of certain liabilities, including our senior notes, upon consummation of the Plan, (ii) fresh start accounting fair value adjustments, (iii) legal and professional advisory fees recognized between the Petition Date and the Emergence Date and (iv) the write-off of debt issuance costs and premiums associated with our senior notes. Refer to the "Chapter 11 Emergence" and "Fresh Start Accounting" footnotes in the notes to the consolidated financial statements for more information on amounts recorded to reorganization items, net. Income Tax Expense (Benefit). During the year endedDecember 31, 2021 we recognized$1 million ofU.S. current income tax expense resulting in an overall effective tax rate of 0.2%, which is lower than the statutory income tax rate as a result of the full valuation allowance on ourU.S. deferred tax assets ("DTAs") as ofDecember 31, 2021 . During the 2020 Combined YTD Period, we recorded a tax benefit of$68 million reflecting a reduction in the overall expected Canadian tax liability as a result of a legal entity restructuring we initiated during the period. Of this reduction,$55 million resulted from the implementation of fresh start accounting and was recorded during the 2020 Predecessor Period and$12 million resulted from the completion of the restructuring and was recorded during the 2020 Successor Period. The remaining$6 million Canadian tax liability was paid in the fourth quarter of 2020. Refer to the "Income Taxes" footnote in the notes to the consolidated financial statements for more information on the legal restructuring and related Canadian deferred tax liability. We also recognized a$1 million U.S. income tax benefit during the 2020 Combined YTD Period related to an alternative minimum tax refund received. As a result of the full valuation allowance on ourU.S. DTAs as ofDecember 31, 2020 (Successor) andAugust 31, 2020 (Predecessor), no additionalU.S. tax benefit or expense was recognized. Our overall effective tax rate of 1.7% for the 2020 Combined YTD Period was lower than theU.S. statutory income tax rate as a result of the full valuation allowance on ourU.S. DTAs and the reduction of our overall expected Canadian tax liability discussed above.
Year Ended
For discussion on the year endedDecember 31, 2020 (which includes the 2020 Successor Period and the 2020 YTD Predecessor Period) compared to the year endedDecember 31, 2019 (Predecessor), refer to Part II, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our 2020 Annual Report on Form 10-K filed with theSEC onFebruary 24, 2021 under the subheading "Successor Period and Current YTD Predecessor Period or Combined Current YTD Period Compared to Prior Predecessor YTD Period."
Liquidity and Capital Resources
Overview. AtDecember 31, 2021 , we had$41 million of unrestricted cash on hand, no long-term debt and$1.7 billion of shareholders' equity, while atDecember 31, 2020 , we had$26 million of unrestricted cash on hand,$360 million of long-term debt and$1.2 billion of equity. We expect that our liquidity going forward will be primarily derived from cash flows from operating activities, cash on hand and availability under the Credit Agreement and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements, as described below, as well as our operating and development activities and planned capital programs. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings or the issuance of common stock or other forms of equity. Cash Flows. During 2021, we generated$740 million of cash from operating activities, an increase of$545 million from the 2020 Combined YTD Period. Cash provided by operating activities increased between periods primarily due to higher realized sales prices, as well as lower cash reorganization, G&A, interest and exploration expenses. These positive factors were partially offset by an increase in cash settlements paid on our commodity derivative contracts and higher production taxes and lease operating expenses between periods. Refer to "Results of Operations" for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods. During 2021, cash flows from operating activities and$180 million of proceeds from the sale of properties were used for the net repayment of$360 million of outstanding borrowings under the Credit Agreement, to fundWilliston Basin acquisitions totaling$306 million and for$234 million of drilling and development expenditures.
For discussion on cash flows for the 2020 Combined YTD Period compared to the
year ended
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One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially mitigate through the use of commodity derivative contracts. Oil accounted for 58% and 61% of our total production in 2021 and 2020, respectively. Natural gas accounted for 21% and 20% of our total production in 2021 and 2020, respectively. NGLs accounted for 21% and 19% of our total production in 2021 and 2020, respectively. As ofFebruary 17, 2022 , we had crude oil derivative contracts (consisting of collars and swaps) covering the sale of 39,000 Bbl and 16,000 Bbl of oil per day for the remainder of 2022 and the first three quarters of 2023, respectively. As ofFebruary 17, 2022 , we had natural gas derivative contracts (consisting of collars, swaps and basis swaps) covering the sale of 95,000 MMBtu and 61,000 MMBtu of natural gas per day through the remainder of 2022 and the first three quarters of 2023, respectively. As ofFebruary 17, 2022 , we had NGL derivative contracts (consisting of swaps) covering the sale of 223,000 gallons of NGLs per day for the remainder of 2022. For more information on our outstanding derivatives refer to the "Derivative Financial Instruments" footnote in the notes to the consolidated financial statements. Material Cash Requirements. Our material short-term cash requirements include dividend payments, payments under our short-term lease agreements, recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. Working capital, defined as total current assets less total current liabilities, fluctuates depending on commodity pricing and effective management of payables to our vendors and receivables from our purchasers and working interest partners. As commodity prices improve, our working capital requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity derivative contracts. Additionally, as discussed in "Recent Developments" above, onFebruary 1, 2022 we entered into a purchase and sale agreement that results in a material short-term cash commitment of$240 million , subject to normal closing adjustments. Our long-term material cash requirements from currently known obligations include repayment of anticipated outstanding borrowings and interest payment obligations under our Credit Agreement, settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, operating and finance lease obligations and contracts to transport a minimum volume of crude oil and natural gas within specified time frames. The following table summarizes our estimated material cash requirements for known obligations as ofDecember 31, 2021 . This table does not include repayments of outstanding borrowings on our Credit Agreement, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. As ofDecember 31, 2021 , we had no outstanding borrowings under our Credit Agreement. Refer to "Credit Agreement" below as well as the "Long-Term Debt" footnote in the notes to the consolidated financial statements for more information. This table also does not include amounts payable under obligations where we cannot forecast with certainty the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. Refer to the "Derivative Financial Instruments" footnote in the notes to the consolidated financial statements for further information on these contracts and their fair values as ofDecember 31, 2021 , which fair values represent the cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date. Refer to the "Commitments and Contingencies" footnote in the notes to the consolidated financial statements in Item 8 of this Annual Report on Form 10-K for more information on other obligations that we may have where the timing and amount of any payments is uncertain. Payments due by period (in thousands) Less than 1 More than Material Cash Requirements Total year 1-3 years 3-5 years 5 years Asset retirement obligations (1)$ 104,067 $ 10,152 $ 23,326 $ 22,923 $ 47,666 Operating leases (2) 20,977 3,572 6,205 3,844 7,356 Finance leases (2) 2,118 1,378 713 27 - Total$ 127,162 $ 15,102 $ 30,244 $ 26,794 $ 55,022
Asset retirement obligations represent the present value of estimated amounts (1) expected to be incurred in the future to plug and abandon oil and gas wells,
remediate oil and gas properties and dismantle their related plants and
facilities.
We have operating and finance leases for corporate and field offices,midstream facilities, equipment and automobiles. The obligations reported (2) above represent our minimum financial commitments pursuant to the terms of
these contracts. Refer to the "Leases" footnote in the notes to the
consolidated financial statements in Item 8 of this Annual Report on Form
10-K for more information on these leases.
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Exploration and Development Expenditures. During 2021 and the 2020 Combined YTD
Period, we incurred accrual basis exploration and development ("E&D")
expenditures of $247 million and $209 million , respectively. Of these
expenditures, 99% and 96%, respectively, were incurred in the Williston Basin of
North Dakota and Montana , where we have focused our current development
activities. Capital expenditures reported in the consolidated statements of
cash flows are calculated on a cash basis, which differs from the accrual basis
used to calculate the incurred capital expenditures as detailed in the table
below:
Successor Predecessor Non-GAAP Predecessor
Year Ended Eight Months Combined Year Year Ended
December 31, Four Months Ended Ended August 31, Ended December 31,
2021 December 31, 2020 2020 December 31, 2020 2019
Capital expenditures, accrual
basis $ 247,201 $ 23,992 $ 185,363 $ 209,355 $ 778,254
Decrease (increase) in
accrued capital expenditures
and other noncash capital
activity (12,764) 9,995 53,093 63,088 15,111
Capital expenditures, cash
basis $ 234,437 $ 33,987 $
238,456 $ 272,443
We continually evaluate our capital needs and compare them to our capital resources. Our 2022 E&D budget is a range of$360 million to$400 million , which we expect to fund with net cash provided by operating activities and cash on hand. Our level of E&D expenditures is largely discretionary, although a portion of our E&D expenditures are for non-operated properties where we have limited control over the timing and amount of such expenditures, and the amount of funds we devote to any particular activity may increase or decrease significantly depending on commodity prices, cash flows, available opportunities and development results, among other factors. We believe that we have sufficient liquidity and capital resources to execute our development plan over the next 12 months. With our expected cash flow streams, commodity price hedging strategies, current liquidity levels (primarily consisting of availability under the Credit Agreement) and flexibility to modify future capital expenditure programs, we expect to fund all planned capital programs, comply with our debt covenants and meet other obligations that may arise from our oil and gas operations. Dividends. InFebruary 2022 , we announced that we would begin paying a quarterly dividend of$0.25 per share with the first dividend to be paid onMarch 15, 2022 . While we believe that our future cash flows from operations can sustain this dividend, future dividends may change based on a variety of factors, including contractual restrictions, legal limitations, business developments and the judgment of our Board. There can be no guarantee that we will pay dividends or otherwise return capital to our shareholders in the future. Credit Agreement.Whiting Petroleum Corporation , as parent guarantor, andWhiting Oil and Gas , as borrower, are parties to the Credit Agreement, a reserves-based credit facility with a syndicate of banks. The Credit Agreement had a borrowing base and aggregate commitments of$750 million as ofDecember 31, 2021 . As ofDecember 31, 2021 , we had no borrowings outstanding under the Credit Agreement with$749 million of available borrowing capacity, which was net of$1 million in letters of credit outstanding. The borrowing base under the Credit Agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations onApril 1 andOctober 1 of each year, as well as special redeterminations described in the Credit Agreement, which in each case may increase or decrease the borrowing base. Additionally, we can increase the aggregate commitments by up to an additional$750 million , subject to certain conditions. Up to$50 million of the borrowing base may be used to issue letters of credit for the account ofWhiting Oil and Gas or our other designated subsidiaries. As ofDecember 31, 2021 ,$49 million was available for additional letters of credit under the Credit Agreement.
The Credit Agreement provides for interest only payments until maturity on
In addition, the Credit Agreement provides for certain mandatory prepayments, including a provision pursuant to which, if our cash balances are in excess of approximately$75 million during any given week, such excess must be utilized to repay borrowings under the Credit Agreement. Interest under the Credit Agreement accrues at our option at either (i) a base rate for a base rate loan plus a margin between 1.75% and 2.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR plus 1.0% per annum, or (ii) an adjusted LIBOR for a eurodollar loan plus a margin between 2.75% and 3.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments.
Additionally, we incur commitment fees of 0.5% on the unused portion of the aggregate commitments of the lenders under the Credit Agreement, which are included as a component of interest expense.
The Credit Agreement contains restrictive covenants that may limit our ability
to, among other things, incur additional indebtedness, sell assets, make loans
to others, make investments, enter into mergers, enter into hedging contracts,
incur liens and engage in certain other transactions without the prior consent
of our lenders. The Credit Agreement also restricts our ability to make any
dividend payments or cash distributions on our common stock except to the extent
that we have distributable free cash flow and (i) have at least 20% of available
borrowing capacity, (ii) have a consolidated net leverage ratio of less than or
equal to 2.0 to 1.0, (iii) do not have a
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borrowing base deficiency and (iv) are not in default under the Credit Agreement. These restrictions apply to all of our restricted subsidiaries and are calculated in accordance with definitions contained in the Credit Agreement.
The Credit Agreement requires us, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 50% of our projected production for the succeeding twelve months, as reflected in the reserves report most recently provided by us to the lenders under the Credit Agreement. If our consolidated net leverage ratio equals or exceeds 1.0 to 1.0 as of the last day of any fiscal quarter, we will also be required to hedge 35% of our projected production for the next succeeding twelve months. We are also limited to hedging a maximum of 85% of our production from proved reserves. The Credit Agreement requires us to maintain the following ratios: (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters' EBITDAX ratio of not greater than 3.5 to 1.0.
For further information on the loan security related to the Credit Agreement, refer to the "Long-Term Debt" footnote in the notes to the consolidated financial statements.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these statements in accordance with GAAP andSEC rules and regulations requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, political environment, global economics, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies is detailed in the "Summary of Significant Policies" footnote in the notes to the consolidated financial statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. Successful Efforts Accounting. We account for our oil and gas operations using the successful efforts method of accounting. Under this method, the fair value of property acquired and all costs associated with successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and gas production costs. All of our properties are located within the continentalUnited States . Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion, impairment of our oil and natural gas properties and our asset retirement obligations. Discounted future net cash flows derived from our reserve estimates were also utilized in establishing the fair value of our oil and natural gas properties upon the adoption of fresh start accounting on the Emergence Date. Proved oil and gas reserves are those quantities of oil and 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. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by theSEC and the FASB. The accuracy of our reserve estimates is a function of (i) the quality and quantity of available data, (ii) the interpretation of that data, (iii) the accuracy of various mandated economic assumptions, and (iv) the judgments of the persons preparing the estimates. Our total proved reserves increased 66 MMBOE, or 25%, fromDecember 31, 2020 toDecember 31, 2021 . Refer to "Reserves" in Item 2 and "Supplemental Disclosures about Oil and Gas Producing Activities" in Item 8 of this Annual Report on Form 10-K for information on the change in reserves between periods. External petroleum engineers independently estimated all of the proved reserve quantities included in this Annual Report on Form 10-K. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information that they use in their evaluation: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data, (4) our well ownership interests and (5) expected future development activity. The independent petroleum engineers,Netherland, Sewell & Associates, Inc. , evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as ofDecember 31, 2021 . Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. For example, if the crude oil and natural gas prices used in our year-end reserve estimates increased or decreased by 10%, our proved reserve quantities atDecember 31, 2021 would have increased by 5 MMBOE (2%) or decreased by 7 MMBOE (2%), respectively, and the pre-tax PV10% of our proved reserves would have increased by$755 million (17%) or decreased by$752 million (17%), respectively. We continually make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates and impairment calculations (when impairment indicators arise) in the same period that changes to reserve estimates are made.
Depreciation, Depletion and Amortization. Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If our estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, which in turn reduces our net income.
Such a decline
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in reserves may result from lower commodity prices or other changes to reserve
estimates, as discussed above, and we are unable to predict changes in reserve
quantity estimates as such quantities are dependent on the success of our
exploration and development program, as well as future economic conditions.Our
DD&A rate declined significantly during both 2021 and the 2020 Successor Period as compared to the 2020 Predecessor Period as a result of our adoption of fresh start accounting on the Emergence Date, which resulted in a reduced book value of our oil and natural gas properties at that date as compared to the 2020 Predecessor Period. Impairment ofOil and Gas Properties . We review the value of our oil and gas properties whenever management judges that events and circumstances indicate that the net carrying value of properties may not be recoverable. Such events and circumstances include, but are not limited to, declines in commodity prices, increases in operating costs, unfavorable reserve revisions, poor well performance, changes in development plans and potential property divestitures. Impairments of producing properties are determined by comparing their undiscounted future net cash flows to their net book values at the end of each period. If a property's net capitalized costs exceed undiscounted future net cash flows, the cost of the property is written down to "fair value," which is determined using discounted future net cash flows from the producing property. Different pricing assumptions or discount rates could result in a different calculated impairment. In addition to proved property impairments, we provide for impairments on significant undeveloped properties when we determine that the property will not be developed or a permanent impairment in value has occurred.
Individually insignificant unproved properties are amortized on a composite basis, based on past success, experience and average remaining lease-term.
Income Taxes. We provide for income taxes in accordance with FASB ASC Topic 740
- Income Taxes ("ASC 740"). We record deferred tax assets and liabilities to
account for the expected future tax consequences of events that have been
recognized in our financial statements and our tax returns. We routinely assess
the realizability of our deferred tax assets. If we conclude that it is more
likely than not that some portion or all of our deferred tax assets will not be
realized, the tax asset is reduced by a valuation allowance. We consider future
taxable income in making such assessments. Numerous judgments and assumptions
are inherent in the determination of future taxable income, including factors
such as future operating conditions, particularly as they relate to prevailing
oil and natural gas prices.
Internal Revenue Code ("IRC") Section 382 addresses company ownership changes
and specifically limits the utilization of certain deductions and other tax
attributes on an annual basis following an ownership change. As a result of the
Chapter 11 reorganization and related transactions, the Successor experienced an
ownership change within the meaning of IRC Section 382 on the Emergence Date.
This ownership change subjected certain of the Company's tax attributes to an
IRC Section 382 limitation. The ownership changes and resulting annual
limitation may result in the expiration of net operating loss carryforwards or
other tax attributes otherwise available, with a corresponding decrease in the
Company's valuation allowance.
We are subject to taxation in many jurisdictions, and the calculation of our tax
liabilities involves dealing with uncertainties in the application of complex
tax laws and regulations in various taxing jurisdictions. If we ultimately
determine that the payment of these liabilities will be unnecessary, we reverse
the liability and recognize a tax benefit during the period in which we
determine the liability no longer applies. Conversely, we record additional tax
charges in a period in which we determine that a recorded tax liability is less
than we expect the ultimate assessment to be.
Reorganization and Fresh Start Accounting. Effective April 1, 2020 , as a result
of the filing of the Chapter 11 Cases we began accounting and reporting
according to FASB ASC Topic 852 - Reorganizations ("ASC 852"), which specifies
the accounting and financial reporting requirements for entities reorganizing
through chapter 11 bankruptcy proceedings. These requirements include
distinguishing transactions associated with the reorganization and
implementation of the plan of reorganization separate from activities related to
ongoing operations of the business. Additionally upon emergence from the
Chapter 11 Cases, ASC 852 requires us to allocate our reorganization value to
our individual assets based on their estimated fair values, resulting in a new
entity for financial reporting purposes. After the Emergence Date, the
accounting and reporting requirements of ASC 852 are no longer applicable and
have no impact on the Successor periods.
Effects of Inflation and Pricing
The oil and gas industry is very cyclical, and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. Higher demand in the industry could result in increases in the costs of materials, services and personnel. Although commodity prices declined sharply during the first part of 2020, the costs of oil field goods and services were slower to decline in response. As commodity prices began to recover during the second half of 2020 and during 2021, the cost of oil field goods and services also rose materially in response to increased competition resulting from increased drilling and completion activity as well as inflationary cost pressures on theU.S. economy. We expect these inflationary pressures to continue throughout 2022. 62 Table of Contents Forward-Looking Statements This report contains statements that we believe to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, dividends and other forms of return of capital, acquisitions and divestitures, projected revenues, earnings, returns, costs, capital expenditures, cash flows and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this report, words such as "expect," "intend," "plan," "estimate," "anticipate," "believe" or "should" or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
These risks and uncertainties include, but are not limited to, risks associated with:
? declines in, or extended periods of low oil, NGL or natural gas prices;
? the occurrence of epidemic or pandemic diseases, including the coronavirus
pandemic;
? action or inaction of the
other oil exporting nations to set and maintain production levels;
? the impacts of hedging on our results of operations;
regulatory developments, including the potential shutdown of the Dakota Access
Pipeline and new or amended federal, state and local initiatives relating to
? the regulation of hydraulic fracturing, air emissions and other aspects of oil
and gas operations that could have a negative effect on the oil and gas
industry and/or increase costs of compliance;
? the geographic concentration of our operations;
? our inability to access oil and gas markets due to market conditions or
operational impediments;
? adequacy of midstream and downstream transportation capacity and
infrastructure;
? shortages of or delays in obtaining qualified personnel or equipment, including
drilling rigs and completion services;
? adverse weather conditions that may negatively impact development or production
activities;
? potential losses and claims resulting from our oil and gas operations,
including uninsured or underinsured losses;
? lack of control over non-operated properties;
? cybersecurity attacks or failures of our telecommunication and other
information technology infrastructure;
? revisions to reserve estimates as a result of changes in commodity prices,
regulation and other factors;
? inaccuracies of our reserve estimates or our assumptions underlying them;
? impact of negative shifts in investor sentiment and public perception towards
the oil and gas industry and corporate governance standards;
? climate change issues;
? litigation and other legal proceedings; and
? other risks described under the caption "Risk Factors" in Item 1A of this
Annual Report on Form 10-K.
We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Annual Report on Form 10-K.
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