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 . We are currently focusing our capital programs on drilling opportunities that we believe provide the greatest well-level returns in order to maintain consistent production levels and generate free cash flow, and are selectively pursuing acquisitions that complement our existing core properties. During 2020, we significantly decreased our level of capital spending to more closely align with our reduced cash flows from operating activities as a result of the sharp decline in commodity prices and our chapter 11 reorganization. During 2021, we are focused on high-return projects in our asset portfolio that will generate significant cash flow from operations as commodity prices begin to recover. 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 the "Acquisitions and Divestitures" footnote in the notes to the consolidated financial statements for more information on our recent acquisition and divestiture activity. Our revenue, profitability, future growth rate and cash flows 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, and the other items discussed under the caption "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the period endedDecember 31, 2020 . 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 Crude oil$ 54.90 $ 59.83 $ 56.45 $ 56.96 $ 46.08 $ 27.85 $ 40.94 $ 42.67 $ 57.80 Natural gas$ 3.00 $ 2.58 $ 2.29 $ 2.44 $ 1.88 $ 1.66
Oil prices improved during the first quarter of 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 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. 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 flows, results of operations, liquidity or ability to fund planned capital expenditures. In addition, lower commodity prices may reduce the amount of our 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"). 27 Table of Contents Recent Developments 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 the Whiting and its financial position and results of operations on or before the Emergence Date. References to "Successor Period" relate to the three months endedMarch 31, 2021 . References to "Predecessor Period" relate to the three months endedMarch 31, 2020 . 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 82.2 MBOE/d for the first quarter of 2021, representing consistent production levels with the fourth quarter of 2020. Across our acreage in theWilliston Basin , we have implemented custom, right-sized completion designs to increase well performance while reducing cost. We continue 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 first quarter of 2021, we had one active completion crew in this area, and we plan to continue at that level for the remainder of 2021. In addition, we resumed drilling in theWilliston Basin in February with one rig, and we plan to add a second rig inOctober 2021 . We drilled 6 gross (4.5 net) wells and TIL 14 gross (9.8 net) wells in this area during the quarter and as ofMarch 31, 2021 , we have 31 gross (19.6 net) drilled uncompleted wells. Under our current 2021 capital program, we expect to TIL approximately 56 gross (36.8 net) wells in this area during the year.
Our properties in the
Net production fromColorado averaged 7.5 MBOE/d for the first quarter of 2021, representing a 9% decrease from the fourth quarter of 2020. Future development activity inColorado is subject to market conditions. 28 Table of Contents 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 a reserves-based credit agreement with a syndicate of banks (the "Credit Agreement"). InApril 2021 , the borrowing base and aggregate commitments of the Credit Agreement of$750 million were reaffirmed in connection with our semi-annual borrowing base redetermination. Refer to the "Long-Term Debt" footnote in the notes to the condensed consolidated financial statements for more information. 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 had violated the National Environmental Policy Act when it granted an easement relating to a portion of the DAPL because it had failed to prepare an environmental impact statement. 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 . OnAugust 5, 2020 , theU.S. Court of Appeals for the D.C. Circuit ("D.C. Appellate Court") granted a stay of the portion of the order directing the shutdown of the DAPL. The stay allowed the DAPL to continue to operate until a further ruling was made. OnJanuary 26, 2021 , the D.C. Appellate Court 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 theU.S. Army Corps of Engineers develops an environmental impact statement.The D.C. District Court is currently considering whether it will issue an injunction that would require a shutdown of the DAPL. We cannot provide any assurance as to the ultimate outcome of the litigation. The disruption of transportation as a result of the DAPL being shut down or the anticipation of 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 or cash flows. To mitigate the potential impact of an unfavorable ruling, we continue to coordinate with our midstream partners and downstream markets to source transportation alternatives. 29 Table of Contents Results of Operations InNovember 2020 , theSEC issued Final Rule 33-10890, Management's Discussion and Analysis, Selected Financial Data and Supplementary Financial Information, which modernizes and simplifies certain disclosure requirements of Regulation S-K. One update to Item 303 of Regulation S-K allows registrants to compare the results of the most recently completed quarter to the results of either the immediately preceding quarter or the corresponding quarter of the preceding year. We have elected to early adopt this update (along with all other updates to Item 303 as a result of the rule) as management believes that comparing current quarter results to those of the immediately preceding quarter is more useful in identifying current business trends and provides a more meaningful comparison. Accordingly, we have compared the results for the three months endedMarch 31, 2021 andDecember 31, 2020 (Successor) below. Additionally, in the first filing after the adoption of this rule change we are required to disclose a comparison of the results for the current quarter and the corresponding quarter of the preceding fiscal year. Accordingly, the comparison between the results for the three months endedMarch 31, 2021 (Successor) andMarch 31, 2020 (Predecessor) is also presented below. Three Months EndedMarch 31, 2021 Compared to Three Months EndedDecember 31, 2020 Successor Three Months Ended March 31, December 31, 2021 2020 Net production Oil (MMBbl) 4.8 5.1 NGLs (MMBbl) 1.6 1.5 Natural gas (Bcf) 10.2 10.7
Total production (MMBOE) 8.1 8.4 Net sales (in millions) Oil (1)$ 256.7 $ 193.6 NGLs 27.0 10.7 Natural gas (1) 21.0 8.0
Total oil, NGL and natural gas sales$ 304.7 $ 212.3 Average sales prices Oil (per Bbl) (1)$ 53.24 $ 37.89 Effect of oil hedges on average price (per Bbl) (8.16)
(0.55)
Oil after the effect of hedging (per Bbl)$ 45.08 $ 37.34 Weighted average NYMEX price (per Bbl) (2)$ 57.83
$ 42.59 NGLs (per Bbl)$ 17.28 $ 6.88 Natural gas (per Mcf) (1) $ 2.05 $ 0.75
Effect of natural gas hedges on average price (per Mcf) 0.01
(0.20)
Natural gas after the effects of hedging (per Mcf) $ 2.06
$ 0.55 Weighted average NYMEX price (per MMBtu) (2) $ 2.56 $ 2.51 Costs and expenses (per BOE) Lease operating expenses $ 7.34 $ 6.57 Transportation, gathering, compression and other $ 0.87 $ 0.72 Production and ad valorem taxes $ 2.99 $ 2.16 Depreciation, depletion and amortization $ 6.64
$ 6.80 General and administrative $ 1.27 $ 1.35
(1) Before consideration of hedging transactions.
(2) Average NYMEX pricing weighted for monthly production volumes.
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Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased$92 million to$305 million when comparing the first quarter of 2021 to the fourth quarter of 2020. 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 the first quarter of 2021 to the fourth quarter of 2020, increases in commodity prices realized between periods accounted for a$103 million increase in revenue, which was partially offset by a decrease in total production between periods that accounted for an$11 million decrease in revenue. Our oil and natural gas volumes decreased 6% and 4% between periods, respectively, and our NGL volumes increased 1%. The overall volume decrease between periods was primarily driven by fewer production days during the first quarter of 2021 as compared to the fourth quarter of 2020. Our average price for oil, NGLs and natural gas (before the effects of hedging) increased 41%, 151% and 173%, respectively, between periods. Our average sales price realized for oil, NGLs and natural gas primarily increased as a result of favorable movements in the NYMEX and Mont Belvieu market indices between periods. Additionally, natural gas average realized price differentials to NYMEX tightened significantly as a result of stronger regional pricing in theWilliston Basin during the first quarter of 2021. Lease Operating Expenses. Our lease operating expenses ("LOE") during the first quarter of 2021 were$59 million , a$4 million increase over the fourth quarter of 2020. This increase between periods was primarily due to an increase in well workover activity during the first quarter of 2021. Our lease operating expenses on a BOE basis also increased when comparing the first quarter of 2021 to the fourth quarter of 2020. LOE per BOE amounted to$7.34 during the first quarter of 2021, which represents an increase of$0.77 per BOE (or 12%) from the fourth quarter of 2020. This increase was mainly due to the overall increase in LOE discussed above and lower overall production volumes between periods.
Transportation, Gathering, Compression and Other. Our transportation,
gathering, compression and other ("TGC") expenses during the first quarter of
2021 were
TGC per BOE also increased when comparing the first quarter of 2021 to the fourth quarter of 2020. TGC per BOE amounted to$0.87 per BOE during the first quarter of 2021, which represents an increase of$0.15 per BOE (or 21%) from the fourth quarter of 2020. This increase was mainly due to lower overall production volumes between periods. Production and Ad Valorem Taxes. Our production and ad valorem taxes during the first quarter of 2021 totaled$24 million , a$6 million increase over the fourth quarter of 2020, which was primarily due to higher sales revenue between periods. Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was 7.6% and 8.1% for the first quarter of 2021 and the fourth quarter of 2020, respectively. Our production tax rate for the first quarter of 2021 was lower than the rate for the fourth quarter of 2020 as certain production taxes levied on natural gas are volume-based and did not increase with the increase in realized prices. Depreciation, Depletion and Amortization. The components of our depletion, depreciation and amortization ("DD&A") expense were as follows (in thousands): Successor Three Months Ended March 31, December 31, 2021 2020 Depletion$ 50,150 $ 53,167 Accretion of asset retirement obligations 2,222 2,872 Depreciation 1,357 1,353 Total$ 53,729 $ 57,392 31 Table of Contents
DD&A decreased between the first quarter of 2021 and the fourth quarter of 2020 primarily due to$3 million in lower depletion expense due to lower overall production volumes between periods, as well as a lower depletion rate between periods. On a BOE basis, our overall DD&A rate of$6.64 per BOE for the first quarter of 2021 was 2% lower than the rate of$6.80 per BOE for the fourth quarter of 2020. The primary factor contributing to this lower DD&A rate was upward revisions to proved reserves during the first quarter of 2021, which were largely driven by higher commodity prices.
Exploration and Impairment Costs. The components of our exploration and impairment expense were as follows (in thousands):
Successor
Three Months Ended
March 31, December 31,
2021 2020
Impairment $ 1,441 $ 3,233
Exploration 1,181 425
Total $ 2,622 $ 3,658
Impairment expense for the first quarter of 2021 primarily related to the
amortization of leasehold costs associated with individually insignificant
unproved properties. Impairment expense for the fourth quarter of 2020
primarily related to (i) the write-off of obsolete equipment inventory and (ii)
the amortization of leasehold costs associated with individually insignificant
unproved properties.
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
Three Months Ended
March 31 , December 31,
2021 2020General and administrative expenses$ 29,210 $
27,750
Reimbursements and allocations (18,919)
(16,361)
General and administrative expenses, net (GAAP) 10,291
11,389
Less: Significant cost drivers (1) -
(3,025)
Non-GAAP general and administrative expenses less significant cost drivers (2)$ 10,291 $
8,364
(1) Includes litigation settlement costs and third-party advisory and legal fees
related to the Chapter 11 Cases.
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 (2) 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.
During the fourth quarter of 2020, we incurred$3 million of costs related to a litigation settlement and third-party advisory and legal fees related to the Chapter 11 Cases which are included in our G&A expense. These costs are generally not expected to reoccur in the future.
G&A expense per BOE amounted to
This decrease was mainly due to the significant cost drivers incurred during the fourth quarter of 2020, partially offset by lower overall production volumes between periods. Derivative (Gain) Loss, Net. Our commodity derivative contracts are marked to market each quarter 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 losses of$147 million and$55 million for the three months endedMarch 31, 2021 andDecember 31, 2020 , respectively. These losses relate to our collar, swap and basis swap commodity derivative contracts and resulted from the upward shift in the futures curve of forecasted commodity prices for crude oil, natural gas and NGLs during the respective periods. 32
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For more information on our outstanding derivatives refer to the "Derivative Financial Instruments" footnote in the notes to the condensed consolidated financial statements.
Interest Expense. The components of our interest expense were as follows (in
thousands):
Successor
Three Months Ended
March 31, December 31,
2021 2020
Credit agreement $ 3,936 $ 4,903 Amortization of debt issue costs, discounts and premiums 887
887
Other 280 162
Total $ 5,103 $ 5,952
Our weighted average borrowings outstanding under the Credit Agreement during
the first quarter of 2021 were $324 million , with a weighted average cash
interest rate of 4.9%. Our weighted average borrowings outstanding during the
fourth quarter of 2020 were $407 million , with a weighted average cash interest
rate of 4.8%.
Income Tax Expense (Benefit). As a result of the full valuation allowance on
our deferred tax assets ("DTAs") as of March 31, 2021 and December 31, 2020 , no
U.S. tax expense or benefit was recognized during the first quarter of 2021 or
the fourth quarter of 2020. An immaterial amount of Canadian income tax expense
was recognized in the fourth quarter of 2020 related to a legal entity
restructuring. Refer to the "Basis of Presentation" footnote in the notes to
the condensed consolidated financial statements for more information on this
restructuring.
Our overall effective tax rates of 0% for the first quarter of 2021 and (14)%
the fourth quarter of 2020 were lower than the U.S. statutory income tax rate
primarily as a result of the full valuation allowance on our U.S. DTAs.
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Successor Period Compared to Predecessor Period
Successor Predecessor
Three Months
Three Months Ended Ended March 31,
March 31, 2021 2020
Net production
Oil (MMBbl) 4.8 6.3
NGLs (MMBbl) 1.6 1.8
Natural gas (Bcf) 10.2 11.6
Total production (MMBOE) 8.1 10.0
Net sales (in millions)
Oil (1) $ 256.7 $ 231.9
NGLs 27.0 10.9
Natural gas (1) 21.0 2.0
Total oil, NGL and natural gas sales $ 304.7 $ 244.8
Average sales prices
Oil (per Bbl) (1) $ 53.24 $ 37.03
Effect of oil hedges on average price (per Bbl) (8.16) 5.08
Oil after the effect of hedging (per Bbl) $ 45.08 $ 42.11
Weighted average NYMEX price (per Bbl) (2) $ 57.83 $ 46.05
NGLs (per Bbl) $ 17.28 $ 6.01
Natural gas (per Mcf) (1) $ 2.05 $ 0.17
Effect of natural gas hedges on average price (per Mcf) 0.01 -
Natural gas after the effect of hedging (per Mcf) $ 2.06 $ 0.17
Weighted average NYMEX price (per MMBtu) (2) $ 2.56 $ 1.88
Costs and expenses (per BOE)
Lease operating expenses $ 7.34 $ 7.22
Transportation, gathering, compression and other $ 0.87 $ 0.89
Production and ad valorem taxes $ 2.99 $ 2.24
Depreciation, depletion and amortization $ 6.64 $ 18.37
General and administrative $ 1.27 $ 4.71
(1) Before consideration of hedging transactions.
(2) Average NYMEX pricing weighted for monthly production volumes.
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased$60 million to$305 million when comparing the Successor Period to the Predecessor 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 the Successor Period to the Predecessor Period, increases in commodity prices realized between periods accounted for a$115 million increase in revenue, which was partially offset by a decrease in total production between periods that accounted for a$55 million decrease in revenue. Our oil, NGL and gas volumes decreased 23%, 14% and 12%, respectively, between periods. The volume decreases between periods were primarily driven by normal field production decline as a result of operational decisions to curtail production, reduce drilling and workover activity, defer completions of certain wells and delay placing some of our completed wells online during the majority of 2020 as a result of sustained lower prices and our bankruptcy filing. This decline was partially offset by production from new wells drilled and completed during the first quarter of 2021 in theWilliston Basin . 34
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Our average price for oil, NGLs and natural gas (before the effects of hedging) increased 44%, 188% and 1,106%, respectively, between periods. Our average realized price for oil, NGLs and natural gas primarily increased as a result of favorable movements in the NYMEX and Mont Belvieu market indices between periods. During the first quarter of 2020, our average realized price for oil was impacted by deficiency payments we made under a physical delivery contract inColorado due to our inability to meet the minimum volume commitments under this contract. During the three months endedMarch 31, 2020 , our total average sales price was$2.91 per Bbl lower as a result of these deficiency payments. Additionally, our oil average realized price differentials to NYMEX improved between periods as a result of lower firm transportation costs, and our natural gas average realized price differentials to NYMEX also improved significantly as a result of stronger regional pricing in theWilliston Basin during the first quarter of 2021. Lease Operating Expenses. Our LOE during the Successor Period was$59 million , a$13 million decrease over the Predecessor Period. This decrease was primarily due to (i) a$7 million decrease in saltwater disposal costs due to reduced completion activity and restructured contracts as a result of the Chapter 11 Cases, (ii) a$3 million decrease in well workover activity and (iii) ongoing cost reduction initiatives which contributed to a$3 million decrease in LOE between periods. Our lease operating expenses on a BOE basis slightly increased when comparing the Successor Period to the Predecessor Period. LOE per BOE amounted to$7.34 during the Successor Period, which represents an increase of$0.12 per BOE (or 2%) from the Predecessor Period. This increase was mainly due to lower overall production volumes between periods, partially offset by the overall decrease in LOE discussed above. Transportation, Gathering, Compression and Other. Our TGC expenses during the Successor Period were$7 million , a$2 million decrease over the Predecessor Period. This decrease mainly relates to lower production volumes between periods and decreased rates negotiated with midstream partners as a result of the Chapter 11 Cases. TGC per BOE also decreased when comparing the Successor Period to the Predecessor Period. TGC per BOE amounted to$0.87 per BOE, which represents a decrease of$0.02 per BOE (or 2%) from the Predecessor Period. This decrease was primarily due to the decreased rates negotiated with midstream partners discussed above. Production and Ad Valorem Taxes. Our production and ad valorem taxes during the Successor Period were$24 million , a$2 million increase over the Predecessor 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 7.6% and 8.8% for the Successor Period and the Predecessor Period, respectively. Our production tax rate for the Successor Period was lower than the rate for the Predecessor Period as certain production taxes levied on natural gas are volume-based and did not increase with the increase in realized prices.
Depreciation, Depletion and Amortization. The components of our DD&A expense were as follows (in thousands):
Successor Predecessor
Three Months
Three Months Ended Ended March 31,
March 31, 2021 2020
Depletion $ 50,150 $ 179,697Accretion of asset retirement obligations 2,222
3,027
Depreciation 1,357 1,244
Total $ 53,729 $ 183,968
DD&A decreased between the Successor Period and the Predecessor Period primarily
due to $130 million in lower depletion expense, consisting of a $12 million
decrease related to lower overall production volumes during the Successor Period
and a $118 million decrease related to a lower depletion rate between periods.
On a BOE basis, our overall DD&A rate of $6.64 per BOE for the Successor Period
was 64% lower than the rate of $18.37 per BOE for the Predecessor Period. The
primary factors contributing to this lower DD&A rate were impairment write-downs
on proved oil and gas properties in the Williston 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. Refer to the "Fresh Start
Accounting" footnote in the notes to the consolidated financial statements in
Item 8 of our 2020 Annual Report on Form 10-K for more information.
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Exploration and Impairment Costs. The components of our exploration and impairment expense were as follows (in thousands):
Successor Predecessor
Three Months
Three Months Ended Ended March 31,
March 31, 2021 2020
Impairment $ 1,441 $ 3,745,092
Exploration 1,181 8,365
Total $ 2,622 $ 3,753,457
Impairment expense for the Successor Period primarily relates to the
amortization of leasehold costs associated with individually insignificant
unproved properties. Impairment expense for the Predecessor Period primarily
relates to (i) a $3.7 billion non-cash impairment charge 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 the properties, and (ii) $12
million in impairment write-downs of undeveloped acreage costs for leases where
we no longer had plans to drill.
General and Administrative Expenses. We report G&A expenses net of third-party
reimbursements and internal allocations. The components of our G&A expenses
were as follows (in thousands):
Successor Predecessor
Three Months Three Months
Ended March 31, Ended March 31,
2021 2020General and administrative expenses$ 29,210 $ 63,912 Reimbursements and allocations (18,919)
(16,745)
General and administrative expenses, net (GAAP) 10,291 47,167 Less: Significant cost drivers (1) -
(16,113)
Non-GAAP general and administrative expenses less significant cost drivers (2)$ 10,291
$ 31,054
Includes cash retention incentives for Predecessor executives and directors (1) and third-party advisory and legal fees related to the Chapter 11 Cases
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 (2) 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 expense before reimbursements and allocations during the Successor Period decreased$35 million compared to the Predecessor Period primarily due to a$19 million decrease in compensation costs as a result of a company restructuring completed in the third quarter of 2020, as well as$16 million of significant cost drivers incurred during the Predecessor Period, including$8 million in cash retention incentives paid to executives and directors and$8 million of third party advisory and legal fees incurred to prepare for the Chapter 11 Cases, which did not reoccur during the Successor Period.
G&A expense per BOE amounted to
This decrease was mainly due to the overall decrease in G&A discussed above partially offset by lower overall production volumes between periods. G&A expense per BOE excluding significant cost drivers was$3.10 per BOE during
the
Predecessor Period.
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Derivative (Gain) Loss, Net. Our commodity derivative contracts are marked to market each quarter 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$147 million and a gain of$231 million for the Successor Period and the Predecessor Period, respectively. These gains and losses relate to our collar, swap and basis 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 the respective periods.
For more information on our outstanding derivatives refer to the "Derivative Financial Instruments" footnote in the notes to the condensed consolidated financial statements.
Interest Expense. The components of our interest expense were as follows (in
thousands):
Successor Predecessor
Three Months
Three Months Ended Ended March 31,
March 31, 2021 2020
Credit agreements $ 3,936 $ 5,518Amortization of debt issue costs, discounts and premiums
887 4,536 Other 280 356 Notes - 34,840 Total $ 5,103 $ 45,250
The decrease in interest expense of$40 million during the Successor Period compared to the Predecessor Period was primarily attributable to lower interest costs incurred on our notes and lower amortization of debt issue costs, discounts and premiums. Upon the filing of the Chapter 11 Cases onApril 1, 2020 , we discontinued accruing 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 a$4 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 condensed consolidated financial statements for more information. Our weighted average debt outstanding during the Successor Period, consisting entirely of borrowings under the Credit Agreement, was$324 million , with a weighted average cash interest rate of 4.9%. Our weighted average debt outstanding during the Predecessor Period, consisting of the notes and borrowings outstanding on the Predecessor Credit Agreement, was$2.9 billion , with a weighted average cash interest rate of 5.5%. Gain on Extinguishment of Debt. During the 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 condensed 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 Predecessor Period. Income Tax Expense (Benefit). As a result of the full valuation allowance on ourU.S. DTAs as ofMarch 31, 2021 (Successor) andMarch 31, 2020 (Predecessor), we did not recognize any income tax expense or benefit during the periods presented, resulting in overall effective tax rates of 0% for both periods.
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Liquidity and Capital Resources
Overview. AtMarch 31, 2021 , we had$25 million of unrestricted cash on hand,$245 million of long-term debt and$1.2 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 pursuits of business opportunities that support our strategy through additional borrowings or the issuance of common stock or other forms of equity. Cash Flows. During the three months endedMarch 31, 2021 (Successor), we generated$153 million of cash from operating activities, an increase of$83 million from the three months endedDecember 31, 2020 (Successor) and an increase of$116 million from the three months endedMarch 31, 2020 (Predecessor). Cash provided by operating activities between Successor periods increased primarily due to higher realized sales prices, as well as lower cash G&A expenses. These positive factors were partially offset by an increase in cash settlements paid on our derivative contracts, higher lease operating expenses and higher production and ad valorem taxes between periods. Cash provided by operating activities increased between the first quarter of 2021 and the Predecessor Period primarily due to higher realized sales prices, as well as lower cash G&A, cash interest expense and lease operating expenses. These positive factors were partially offset by an increase in cash settlements paid on our derivative contracts. 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 the three months endedMarch 31, 2021 , cash flows from operating activities and proceeds from the sale of properties were used for the repayment of$115 million of net outstanding borrowings under the Credit Agreement and$36 million of drilling and development expenditures. 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 hedge contracts. As ofApril 30, 2021 , we had crude oil derivative contracts (consisting of collars, swaps and differential swaps) covering the sale of 35,000 Bbl, 27,000 Bbl and 15,000 Bbl of oil per day for the remainder of 2021, the full year 2022 and the first six months of 2023, respectively. As ofApril 30, 2021 , we had natural gas derivative contracts (consisting of collars, swaps and basis swaps) covering the sale of 102,000 MMBtu, 52,000 MMBtu and 49,000 MMBtu of natural gas per day through the remainder of 2021, the full year 2022 and the first six months of 2023, respectively. As ofApril 30, 2021 , we had NGL derivative contracts (consisting of swaps) covering the sale of 63,000 gallons of NGLs per day for the remainder of 2021. For more information on our outstanding derivatives refer to the "Derivative Financial Instruments" footnote in the notes to the condensed consolidated financial statements. Material Cash Requirements. Our material short-term cash requirements include 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 receivables from our purchasers and working interest partners and payables to our vendors. 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 hedge contracts. Our long-term material cash requirements from currently known obligations include repayment of outstanding borrowings and interest payment obligations under our Credit Agreement, settlements on our outstanding commodity hedge 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 ofMarch 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 ofMarch 31, 2021 , our outstanding borrowings under our Credit Agreement were$245 million , with a weighted average interest rate on the outstanding principal balance of 4.2%. Refer to "Credit Agreement" below as well as the "Long-Term Debt" footnote in the notes to the condensed consolidated financial statements for more information. This table also does not include amounts payable under obligations where we cannot forecast with certainty the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. Refer to the "Derivative Financial Instruments" footnote in the notes to the condensed consolidated financial statements for further information on these contracts and their fair values as ofMarch 31, 2021 , which fair values represent the cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date. 38 Table of Contents Payments due by period (in thousands) Less than 1 More than 5 Material Cash Requirements Total year 1-3 years 3-5 years years Asset retirement obligations (1)$ 106,006 $ 6,735
45,827$ 13,597 $ 39,847 Operating leases (2) 23,882 3,743 6,709 4,563 8,867 Finance leases (2) 18,135 5,269 8,087 4,779 -
Pipeline transportation agreements (3) 11,717 6,431
4,739 547 - Total$ 159,740 $ 22,178 $ 65,362 $ 23,486 $ 48,714
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,pipeline and midstream facilities and automobiles. The obligations reported
above represent our minimum financial commitments pursuant to the terms of (2) these contracts, however our actual expenditures under these contracts may
exceed the minimum commitments presented above. Refer to the "Leases"
footnote in the notes to the consolidated financial statements in Item 8 of
our Annual Report on Form 10-K for the year ended
information on these leases.
Our pipeline transportation agreements consist of contracts through 2024 with
various third parties to facilitate the delivery of our produced oil, gas and
NGLs to market. These contracts require either fixed monthly reservation
fees or commitments to deliver minimum volumes at fixed rates in exchange for (3) dedicated pipeline capacity. If minimum volume commitments are not met, we
are required to pay any deficiencies at the prices stipulated in the
contracts. The obligations reported above represent our minimum financial
commitments pursuant to the terms of these contracts, however, our actual
expenditures under these contracts may exceed the minimum commitments
presented above.
Exploration and Development Expenditures. During the three months endedMarch 31, 2021 and 2020, we incurred accrual basis exploration and development ("E&D") expenditures of$56 million and$146 million , respectively. Of these expenditures, 98% and 94%, respectively, were incurred in our large resource play in theWilliston Basin ofNorth Dakota andMontana , where we have focused our current development. Capital expenditures reported in the condensed consolidated statements of cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the incurred capital expenditures detailed in the table below: Successor Predecessor Three Months Three Months EndedMarch 31 , EndedMarch 31, 2021 2020
Capital expenditures, accrual basis$ 55,602 $ 145,965 Decrease (increase) in accrued capital expenditures (19,874) 334 Capital expenditures, cash basis$ 35,728
$ 146,299
We continually evaluate our capital needs and compare them to our capital resources. Our 2021 E&D budget is a range of$228 million to$252 million , which we expect to fund with net cash provided by operating activities and cash on hand, and represents a slight increase from the E&D expenditures incurred during 2020. 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 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. 39
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Credit Agreement.Whiting Petroleum Corporation , as parent guarantor, andWhiting Oil and Gas , as borrower, have a reserves-based credit facility, with a syndicate of banks that had a borrowing base and aggregate commitments of$750 million as ofMarch 31, 2021 . As ofMarch 31, 2021 , we had$503 million of available borrowing capacity under the Credit Agreement, which was net of$245 million of borrowings outstanding and$2 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 such lenders, and is subject to regular redeterminations onApril 1 andOctober 1 of each year, as well as special redeterminations described in the Credit Agreement, in each case which may increase or decrease the amount of the borrowing base. InApril 2021 , our borrowing base and aggregate commitments of$750 million were reaffirmed in connection with our regular borrowing base redetermination. Future asset sales that materially impact the value of our proved reserves may result in a reduction of our borrowing base. However, we can increase the aggregate commitments by up to an additional$750 million , subject to certain conditions. A portion of the revolving credit facility in an aggregate amount not to exceed$50 million may be used to issue letters of credit for the account ofWhiting Oil and Gas or our other designated subsidiaries. As ofMarch 31, 2021 ,$48 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. Except for limited exceptions, the Credit Agreement also restricts our ability to make any dividend payments or distributions on our common stock prior toSeptember 1, 2021 , and thereafter only 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 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 65% of our projected production for the succeeding twelve months, and 35% of our projected production for the next succeeding twelve months, both as reflected in our reserves report most recently provided to the lenders under the Credit Agreement. 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 condensed consolidated financial statements.
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Critical Accounting Policies and Estimates
Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year endedDecember 31, 2020 . No material updates were made to such critical accounting policies and estimates during the three months endedMarch 31, 2021 .
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, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this report, words such as we "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 our emergence from bankruptcy; declines in, or extended periods of low oil, NGL or natural gas prices; the occurrence of epidemic or pandemic diseases, including the coronavirus pandemic; actions of theOrganization of Petroleum Exporting Countries and other oil exporting nations to set and maintain production levels; the potential shutdown of the Dakota Access Pipeline; our level of success in development and production activities; impacts resulting from the allocation of resources among our strategic opportunities; our ability to replace our oil and natural gas reserves; the geographic concentration of our operations; our inability to access oil and gas markets due to market conditions or operational impediments; market availability of, and risks associated with, transport of oil and gas; weakened differentials impacting the price we receive for oil and natural gas; our ability to successfully complete asset acquisitions and dispositions and the risks related thereto; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; the timing of our development expenditures; properties that we acquire may not produce as projected and may have unidentified liabilities; adverse weather conditions that may negatively impact development or production activities; we may incur substantial losses and be subject to liability claims as a result of our oil and gas operations, including uninsured or underinsured losses resulting from our oil and gas operations; lack of control over non-operated properties; unforeseen underperformance of or liabilities associated with acquired properties or other strategic partnerships or investments; competition in the oil and gas industry; cybersecurity attacks or failures of our telecommunication and other information technology infrastructure; our ability to comply with debt covenants, periodic redeterminations of the borrowing base under our Credit Agreement and our ability to generate sufficient cash flows from operations to service our indebtedness; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; 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; the impacts of hedging on our results of operations; our ability to use net operating loss carryforwards in future periods; impacts to financial statements as a result of impairment write-downs and other cash and noncash charges; the impact of negative shifts in investor sentiment towards the oil and gas industry; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; the Biden administration could enact regulations that impose more onerous permitting and other costly environmental, health and safety requirements; the impact and costs of compliance with laws and regulations governing our oil and gas operations; the potential impact of changes in laws that could have a negative effect on the oil and gas industry; impacts of local regulations, climate change issues, negative perception of our industry and corporate governance standards; negative impacts from litigation and legal proceedings; and other risks described under the caption "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the period endedDecember 31, 2020 . We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Quarterly Report on Form 10-Q. 41 Table of Contents
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