Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: “Business” in Item 1 and “Financial Statements and Supplementary Data” in Item 8. Our discussion and analysis includes the following subjects:
• Overview;
• Consolidated Results of Operations;
• Liquidity and Capital Resources;
• Valuation Allowance; and
• Critical Accounting Policies and Estimates.
Overview
We are an independent oil and natural gas company with a principal focus on acquisition, development and production activities in the U.S. Mid-Continent and North Park Basin of Colorado. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.
Operational Activities
There was no drilling activity during the year ended December 31, 2020. Operational activities for the year ended December 31, 2019 included the following:
Year Ended December 31,
2019
Gross Wells Drilled Net Wells Drilled Average Rigs Drilling
Area
Mid-Continent (1)
11 3.9 0.6
North Park Basin
10 10.0 0.4
Total
21 13.9 1.0
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(1) Eight wells were drilled under our previous drilling participation agreement during the year ended December 31, 2019. Under this agreement, we receive a 20% net working interest after funding 10% of the drilling and completion costs related to the subject wells. The last well under this agreement was completed in the second quarter of 2019.
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The chart below shows production by product for the years ended December 31, 2020 and 2019:
(1) For the year ended December 31, 2020, Mid-Continent production was 3,925 MBoe in natural gas, 2,694 MBoe in NGLs and 1,144 MBoe in oil totaling 7,763 MBoe. North Park Basin had 940 MBoe in oil.
(2) For the year ended December 31, 2019, Mid-Continent production was 5,527 MBoe in natural gas, 2,908 MBoe in NGLs and 1,988 MBoe in oil totaling 10,423 MBoe. North Park Basin had 1,531 MBoe in oil and 2 MBoe in NGLs totaling 1,533 MBoe.
Total production for 2020 was comprised of approximately 23.9% oil, 45.1% natural gas and 31.0% NGLs compared to 29.4% oil, 46.2% natural gas and 24.4% NGLs in 2019.
Recent Events
• On March 3, 2021, the Company named Mr. Grayson Pranin, formerly its Vice President for Reserves and Engineering, as Senior Vice President and Chief Operating Officer. The Company also named Mr. Salah Gamoudi, the Company’s Chief Financial Officer and Chief Accounting Officer, as a Senior Vice President. It also named Mr. Dean Parrish, formerly its Director of Operations, as its Vice President of Operations.
• On February 5, 2021, we sold all of our oil and natural gas properties and related assets of the North Park Basin in Colorado for a purchase price of $47 million in cash. The sale closed for net proceeds of $39.7 million in cash, which is net of effective to closing date adjustments.
• SandRidge Mississippian Trust I: We are party to the Amended and Restated Trust Agreement of SandRidge Mississippian Trust I (the “SDT Trust”), dated April 12, 2011, by and among the Company, the Bank of New York Mellon Trust Company, N.A., and the Corporation Trust Company (the “Trust Agreement”). Pursuant to the Trust Agreement, we have a right of first refusal with respect to any sale of assets of the SDT Trust to a third party following the occurrence of certain events (a “Triggering Event”). On October 23, 2020, the SDT Trust announced the Trust will be required to dissolve and commence winding up beginning as of the close of business on November 13, 2020. At December 31, 2020, the market capitalization of the SDT Trust was $5.1 million of which we own approximately 26.9%.
• On September 10, 2020, the Company closed on the acquisition of the overriding royalty interests of SandRidge Mississippian Trust II for a gross purchase price of $5.25 million (net purchase price of $3.28 million, given the Company's 37.6% ownership of the Trust).
• On August 31, 2020, SandRidge Realty, LLC, a wholly owned subsidiary of the Company, closed on the sale of the Company's 30-story office tower and annex with parking and ancillary uses located at 123 Robert S. Kerr, Oklahoma City, Oklahoma 73102, for net proceeds of approximately $35.4 million.
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• On July 1, 2020, the Board declared a dividend distribution of one right (a “Right”) for each outstanding share of Company common stock, par value $0.001 per share to stockholders of record at the close of business on July 13, 2020. Each Right entitles its holder, under certain circumstances, to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock of the Company, par value $0.001 per share, at an exercise price of $5.00 per Right, subject to adjustment. The description and terms of the Rights are set forth in the tax benefits preservation plan, dated as of July 1, 2020, between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (and any successor rights agent, the “Rights Agent”).
Outlook
As discussed in “Business— Our Business Strategy” in Item 1 of this report, we will focus on maximizing free cash flow in 2021 through a combination of cost control measures and the continued exercise of financial discipline and prudent capital allocation, which includes limiting our drilling capital to locations we believe will provide high rates of return in the current commodity price environment. As a result, our planned capital expenditures for 2021 will be similar to our 2020 levels. Given this expected level of capital expenditures, our oil, natural gas and NGL production will likely decline in 2021. We will be prepared to expand our capital program after considering all factors including commodity prices. We will also continue our pursuit of acquisitions and business combinations which provide high margin properties with attractive returns at current commodity prices.
The COVID-19 pandemic and other pricing volatility caused by the announcement of production increases by Saudi Arabia-led OPEC and Russia caused a steep decline in oil prices in March 2020, which further decreased to historic lows in April 2020. Although we cannot reasonably estimate what the full impact of the COVID-19 pandemic and other market volatility will have on our business, it could have a material, adverse impact on near-term future revenues and overall profitability. Additionally, we have implemented several additional initiatives to maximize free cash flow, reduce our debt level, maximize our liquidity position and, ultimately realize greater shareholder value. These initiatives included personnel and non-personnel cost reductions, the sale of the company headquarters during 2020. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.
Consolidated Results of Operations
The majority of our consolidated revenues and cash flow are generated from the production and sale of oil, natural gas and NGLs. Our revenues, profitability and future growth depend substantially on prevailing prices received for our production, the quantity of oil, natural gas and NGLs we produce, and our ability to find and economically develop and produce our reserves. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. To provide information on the general trend in pricing, the average annual NYMEX prices for oil and natural gas for recent years are presented in the table below:
Year Ended December 31,
2020 2019
Oil (per Bbl) $ 39.19 $ 57.04
Natural gas (per Mcf) $ 2.13 $ 2.53
In order to reduce our exposure to price fluctuations, we have historically entered into commodity derivative contracts for a portion of our anticipated future oil and natural gas production as discussed in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” Reducing the Company’s exposure to price volatility helps mitigate the risk that we will not have adequate funds available to support our operations. During periods where the strike prices for our commodity derivative contracts are below market prices at the time of settlement, we may not fully benefit from increases in the market price of oil and natural gas. Conversely, during periods of declining market prices of oil and natural gas, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement. However, as of December 31, 2020, the Company had no remaining open commodity derivative contracts.
Acquisitions and Divestitures of Properties
2020 Acquisitions and Divestitures
On September 10, 2020, the Company acquired all of the overriding royalty interests held by SandRidge Mississippian Royalty Trust II ("the Trust") for a net purchase price of $3.28 million, given our 37.6% ownership of the Trust. The Company
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accounted for this transaction as an asset acquisition and allocated the purchase price of the acquisition plus the transactions costs to oil and gas properties.
On August 31, 2020, the Company closed on the previously announced sale of its corporate headquarters building located in Oklahoma City, OK, for net proceeds of approximately $35.4 million.
See "Note 22 — Subsequent Event” to the accompanying consolidated financial statements in Item 8 of this report. for information related to the February 5, 2021 sale of our North Park Basin assets.
2019 Acquisitions and Divestitures
Nonmonetary transaction. During the three-month period ended September 30, 2019, the Company transferred its interest in certain proved oil and natural gas properties located in Comanche, Harper and Sumner counties in Kansas along with associated electrical infrastructure and an insignificant amount of accounts receivable with an aggregate estimated fair value of $5.4 million, for an interest in certain other proved oil and natural gas properties located in Comanche, Harper and Barber counties in Kansas. The fair value of the non-oil and gas assets given in the transaction approximated their carrying value, therefore no gain or loss was recognized on the transfer.
Oil, Natural Gas and NGL Production and Pricing
The table below presents production and pricing information for the years ended December 31, 2020, and 2019.
Year Ended December 31,
2020 2019
Production data (in thousands)
Oil (MBbls) 2,084 3,519
NGL (MBbls) 2,694 2,910
Natural gas (MMcf) 23,552 33,164
Total volumes (MBoe) 8,703 11,956
Average daily total volumes (MBoe/d) 23.8 32.8
Average prices—as reported (1)
Oil (per Bbl) $ 35.33 $ 52.96
NGL (per Bbl) $ 6.67 $ 12.23
Natural gas (per Mcf) $ 0.97 $ 1.33
Total (per Boe) $ 13.15 $ 22.26
Average prices—including impact of derivative contract settlements (2)
Oil (per Bbl) $ 40.10 $ 53.30
NGL (per Bbl) $ 6.67 $ 12.23
Natural gas (per Mcf) $ 0.80 $ 1.48
Total (per Boe) $ 13.83 $ 22.78
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(1) Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.
(2) Excludes early settlements of commodity derivative contracts prior to their contractual maturity.
The table below presents production by area of operation for the years ended December 31, 2020 and 2019, and illustrates the impact of (i) natural declines in existing producing wells in the Mid-Continent, (ii) No new wells in 2020.
Year Ended December 31,
2020 2019
Production (MBoe) % of Total Production Production (MBoe) % of Total Production
Mid-Continent 7,763 89.2 % 10,423 87.2 %
North Park Basin 940 10.8 % 1,533 12.8 %
Total 8,703 100.0 % 11,956 100.0 %
Revenues
Consolidated revenues for the years ended December 31, 2020 and 2019 are presented in the table below (in thousands).
Year Ended December 31,
2020 2019
Revenues
Oil $ 73,621 $ 186,360
NGL 17,962 35,598
Natural gas 22,867 44,146
Other 526 741
Total revenues $ 114,976 $ 266,845
Variances in oil, natural gas and NGL revenues attributable to changes in the average prices received for our production and total production volumes sold for the years ended December 31, 2020 and 2019 are shown in the table below (in thousands):
2019 oil, natural gas and NGL revenues
$ 266,104
Change due to production volumes in 2020 (42,779)
Change due to average prices in 2020 (108,875)
2020 oil, natural gas and NGL revenues $ 114,450
Oil, natural gas and NGL revenues decreased by a combined $151.7 million, or 57.0% for the year ended December 31, 2020, compared to 2019. The average prices for oil, natural gas and NGL's declined significantly during 2020, due largely to an increase in anticipated global supplies of these commodities after a pledged increase in oil production from Saudi Arabia-led OPEC, and the reduction in demand stemming from the COVID-19 pandemic. See “Item 1A. Risk Factors” included in Part I of this Annual Report for additional discussion of the potential impact these events may have on our future revenues.
The decline in production for the year ended December 31, 2020 compared to 2019, largely resulting from the absence of newly drilled wells in 2020 and natural production declines in our existing producing wells in the Mid-Continent and North Park Basin. North Park Basin ("NPB") represented $31.1 million, or 27.0% of the Company's $115.0 million total consolidated Revenues for the year ended December 31, 2020.
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Operating Expenses
Operating expenses for the years ended December 31, 2020, and 2019 consisted of the following (in thousands):
Year Ended December 31,
2020 2019
Lease operating expenses $ 43,431 $ 90,938
Production, ad valorem, and other taxes 9,634 19,394
Depreciation and depletion—oil and natural gas 50,349 146,874
Depreciation and amortization—other 7,736 11,684
Total operating expenses $ 111,150 $ 268,890
Lease operating expenses ($/Boe) $ 4.99 $ 7.61
Production, ad valorem, and other taxes ($/Boe) $ 1.11 $ 1.62
Depreciation and amortization—oil and natural gas ($/Boe) $ 5.11 $ 12.28
Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) 8.4 % 7.3 %
Lease operating expenses for 2020 decreased $47.5 million, or $2.62/Boe from 2019. This decrease primarily resulted from field personnel reductions in force, in addition to the shut-in of wells that had become uneconomic due to natural production declines and deteriorating pricing during the year ended December 31, 2020. NPB represented $9.1 million, or 20.9% of the Company's $43.4 million consolidated Lease operating expense for the year ended December 31, 2020.
Production, ad valorem, and other taxes has decreased primarily due to declining production and revenues. Further, they have increased as a percentage of oil, natural gas, and NGL revenue for the year 2020 compared to 2019, primarily due to ad valorem taxes remaining consistent throughout 2020 while revenues have declined during 2020. NPB represented $1.8 million, or 18.7% of the Company's $9.6 million consolidated Production, ad valorem and other taxes for the year ended December 31, 2020.
Depreciation and depletion for oil and natural gas properties decreased by $96.5 million for the year ended December 31, 2020 compared to 2019 due to an decrease in the average depreciation and depletion rate to $5.11 per Boe in 2020 compared to an average rate of $12.28 in 2019. This rate decrease is primarily due to the full cost ceiling test impairments recorded in the third and fourth quarters of 2019, as well as the ceiling test impairments recorded in 2020.
Impairment
Impairment expense for the years ended December 31, 2020, and 2019 consisted of the following (in thousands):
Year Ended December 31,
2020 2019
Impairment
Full cost pool ceiling limitation $ 218,399 $ 409,574
Other 38,000 —
Total impairment $ 256,399 $ 409,574
Full cost pool impairment. Impairment for the year ended December 31, 2020 largely resulted from an impairment charge of $256.4 million, which included a full cost ceiling limitation impairment charge of $218.4 million, and an impairment charge of $38 million to write down the value of the Company's office headquarters to its estimated fair value less estimated costs to sell the building. For the quarter ended December 31, 2020, we recorded a full cost ceiling limitation impairment charge of $2.6 million.
Calculation of the full cost ceiling test is based on, among other factors, trailing twelve-month SEC prices as adjusted for price differentials and other contractual arrangements. The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at December 31, 2020 were $39.57 per barrel of oil and $1.99 per Mcf of natural gas, before price differential adjustments.
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Based on the SEC prices over the eleven months ended February 1, 2021, as well as the short-term pricing outlook for the remainder of the first quarter 2021, we anticipate the SEC prices utilized in the March 31, 2021 full cost ceiling test may be $39.42 per barrel of oil and $2.16 per Mcf of natural gas, (the "estimated first quarter prices"). Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2020 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2021.
However, a full cost ceiling limitation impairment may still be realized in the first quarter of 2021 and in subsequent quarters based on the outcome of numerous other factors such as additional declines in the actual trailing twelve-month SEC prices, lower NGL pricing, changes in estimated future development costs and operating expenses, and other adjustments to our levels of proved reserves. Any such ceiling test impairments in 2021 could be material to our net earnings.
Non-Operating Expenses
Non-operating expenses for the years ended December 31, 2020, and 2019 consisted of the following (in thousands):
Year Ended December 31,
2020 2019
General and administrative $ 15,327 $ 32,058
Restructuring expenses 2,733 —
Employee termination benefits 8,433 4,792
Gain on derivative contracts (5,765) (1,094)
Other operating expense (income) 206 (608)
Total non-operating expenses $ 20,934 $ 35,148
General and administrative expenses decreased $16.7 million, or 52.2%, for the year ended December 31, 2020 compared to 2019 primarily from a reduction in compensation related costs after completing reductions in force during the second quarter of 2019 and the first three quarters of 2020. Part of the decrease is also due to reductions in professional costs such as legal expenses, technology, software, audit fees and consulting services.
Restructuring expenses represent fees and costs associated with our outsourcing and relocation of certain corporate specific functions that are of a non-recurring nature and expenses related to the 2016 bankruptcy.
Employee termination benefits for the year ended December 31, 2020, include cash and share-based severance costs incurred primarily as a result of the reduction in force. On July 1, 2020, the Company's then current Chief Financial Officer, Michael A. Johnson and Chief Operating Officer, John Suter, separated employment from the Company. As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with these separations during 2020.
Employee termination benefits for the year ended December 31, 2019, include cash and share-based severance costs incurred related to (i) a reduction in force in the second quarter of 2019 and (ii) severance costs associated with the departure of our former Executive Vice President, General Counsel and Corporate Secretary, Phil Warman, and former CEO, Paul McKinney.
See "Note 19 — Employee Termination Benefits" to the accompanying consolidated financial statements in Item 8 of this report for additional information.
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We recorded a net gain on commodity derivative contracts of $5.8 million and $1.1 million for the years ended December 31, 2020, and 2019, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash receipts upon settlement of $5.9 million and $6.3 million, respectively.
Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded each quarter as a component of operating expenses. Internally, management views the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil and natural gas production to determine “effective prices.” In general, cash is received on settlement of contracts due to lower oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts, and cash is paid on settlement of contracts due to higher oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts. See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” of this report for additional discussion of our commodity derivatives.
Other Income (Expense)
Other income (expense) for the years ended December 31, 2020, and 2019 is reflected in the table below (in thousands):
Year Ended December 31,
2020 2019
Other (expense) income
Interest expense, net $ (1,998) $ (2,974)
Other (expense) income , net (2,494) 436
Total other (expense) income $ (4,492) $ (2,538)
Interest expense for the years ended December 31, 2020, and 2019 consisted of the following (in thousands):
Year Ended December 31,
2020 2019
Interest expense
Interest expense on debt $ 2,387 $ 3,658
Interest expense on right of use assets 114 160
Write off of debt issuance costs 266 142
Amortization of debt issuance costs, premium and discounts — 558
Capitalized interest (750) (1,453)
Total 2,017 3,065
Less: interest income (19) (91)
Total interest expense, net $ 1,998 $ 2,974
Interest expense incurred during the year ended December 31, 2020 is primarily comprised of interest and fees paid on the Prior Credit Facility that was terminated on November 30, 2020. Interest expense incurred during the year ended December 31, 2019 is primarily comprised of interest and fees paid on the Prior Credit Facility.
See “Note 11 — Long-Term Debt” to the accompanying consolidated financial statements in Item 8 of this report for additional discussion of our long-term debt transactions.
The Other (expense) income, net line item for the year ended December 31, 2020 includes an allowance for doubtful accounts of $2.5 million that was recorded as a result of conducting an assessment of governmental and other regulatory receivable balances, which we have deemed as potentially uncollectible. This allowance is non-recurring in nature, and does not represent allowances for doubtful accounts related to joint interest billing receivables or other recurring items.
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Liquidity and Capital Resources
At December 31, 2020, our cash and cash equivalents, excluding restricted cash, were $22.1 million. Additionally, we had a $20.0 million term loan outstanding and $10.0 million available under our $30.0 million New Credit Facility, which matures on November 30, 2023. See "Note — 11 Long-Term Debt" to the accompanying consolidated financial statements in Item 8 of this report. for further discussion. As of March 1, 2021, the Company had, no outstanding balance under the New Credit Facility revolving line of credit, and a $20.0 million outstanding term loan under the New Credit Facility.
As discussed in “— Recent Events” and “— Outlook” above, we have undertaken several initiatives in 2020, which we believe have the potential to positively impact our liquidity. These initiatives are expected to maximize free cash flow and ultimately realize greater shareholder value to address the negative impact of the COVID-19 pandemic and commodity price volatility on our financial position and future liquidity. These initiatives included personnel and non-personnel cost reductions the sale of our corporate headquarters, and the signing of a purchase and sale agreement to sell our North Park Basin assets.
We are unable to project the full impact the COVID-19 pandemic will have on our financial position and results of operations at this time, but these measures, along with amounts available to be drawn on our New Credit Facility, cash on hand, and other cash flows from operations are expected to provide ample liquidity for the next 12 months.
Working Capital and Sources and Uses of Cash
Our principal sources of liquidity for 2020 included cash flow from operations, cash on hand and amounts available under our New Credit Facility, as discussed in “—Credit Facility” below. As discussed in “— Outlook” above to the accompanying audited consolidated financial statements and “Item 1A. Risk Factors” included in Part I of this Annual Report, we expect the COVID-19 pandemic and other market volatility factors to have a material, adverse impact on future revenue growth and overall profitability for the foreseeable future.
Our working capital deficit decreased to $18.1 million at December 31, 2020, compared to $49.8 million at December 31, 2019, the positive impact on working capital resulted primarily from an increase in cash and cash equivalents at December 31, 2020 as a result of proceeds from asset sales, cash from operations and the new term loan. In addition, accounts payable decreased due to a decline in drilling and completions activity in 2020, in addition to our cost reduction efforts..
We intend to spend between $5 million and $10 million in our 2021 capital budget plan, excluding any expenditures for acquisitions. We intend to fund capital expenditures and other commitments for the next 12 months using cash flows from our operations, borrowings under our New Credit Facility and cash on hand. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.
Cash Flows
Our cash flows from operations are substantially dependent on current and future prices for oil and natural gas, which historically have been, and may continue to be, volatile. For example, during the period from January 2016 through December 2020, the NYMEX settled price for oil fluctuated between a high of $77.41 per Bbl and a low of $(36.98) per Bbl, and the month-end NYMEX settled price for gas fluctuated between a high of $4.84 per MMBtu and a low of $1.48 per MMBtu.
If oil or natural gas prices decline from current levels, they could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. This could result in full cost pool ceiling impairments. Further, if our future capital expenditures are limited or deferred, or we are unsuccessful in developing reserves and adding production through our capital program, the value of our oil and natural gas properties, financial condition and results of operations could be adversely affected.
Cash flows for the years ended December 31, 2020, and 2019 are presented in the following table and discussed below (in thousands):
Year Ended December 31,
2020 2019
Cash flows provided by operating activities $ 36,162 $ 121,324
Cash flows provided by (used in) investing activities 25,093 (189,849)
Cash flows (used in) provided by financing activities (38,957) 54,848
Net increase (decrease) in cash and cash equivalents $ 22,298 $ (13,677)
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Cash Flows from Operating Activities
The $85.2 million decrease in operating cash flows for the year ended December 31, 2020 compared to 2019, is primarily due the significant decline in revenues, which was partially offset by reductions in general and administrative costs and lease operating expenses as well as the other changes in working capital discussed previously.
See “—Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses, and see “Note 19 — Employee Termination Benefits” to the accompanying consolidated financial statements included in Item 8 of this report for additional detail on cash paid for employee termination benefits.
Cash Flows from Investing Activities
During the year ended December 31, 2020, cash flows provided by investing activities primarily reflects $35.4 million of net cash proceeds primarily from the sale of the corporate office building, offset by cash payments made for capital expenditures coupled with the acquisition of $3.3 million primarily related to overriding royalty interests. See "Note 3 — Acquisitions, Divestitures and Disposal of Assets and Oil and Gas Properties" to the accompanying consolidated financial statements included in Item 8 of this report for additional information.
During the year ended December 31, 2019, cash flows used in investing activities primarily consisted of capital expenditures for drilling and completion activities partially offset by proceeds from the sale of assets.
Capital Expenditures.
Our capital expenditures for the years ended December 31, 2020 and 2019, are summarized below (in thousands):
Year Ended December 31,
2020 2019
Capital Expenditures
Drilling, completion, and capital workovers $ 3,563 $ 157,999
Leasehold and geophysical 1,005 3,790
Other - corporate — 245
Capital expenditures, excluding acquisitions (on an accrual basis) 4,568 162,034
Acquisitions (1) 3,701 (236)
Current year total capital expenditures, including acquisitions 8,269 161,798
Change in capital accruals (2) 4,194 29,644
Total cash paid for capital expenditures $ 12,463 $ 191,442
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(1) Excludes $3.9 million and $5.4 million for the years ended December 31, 2020 and December 31, 2019, respectively, related to nonmonetary transactions.
(2) Reflects cash paid during the period presented for expenditures related to the prior year's capital program.
Capital expenditures, excluding acquisitions, for development and production activities decreased for the year ended December 31, 2020 compared to 2019, which is in line with the planned decrease in drilling and completion activity and related costs as reflected in our lower capital expenditures budget in 2020 and 2019.
Cash Flows from Financing Activities
Our financing activities used $39.0 in of cash for the year ended December 31, 2020, which consisted primarily of $57.5 million of net repayments of borrowings under the Prior Credit Facility partially offset by $20.0 million in proceeds from the New Credit Facility.
.
Our financing activities provided $54.8 million of cash for the year ended December 31, 2019, which consisted primarily of proceeds from borrowings from our Prior Credit Facility during each period.
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Indebtedness
Credit Facility
Credit Facility. On November 30, 2020, the Company entered into a $30 million New Credit Facility with the lenders party thereto and Icahn Agency Services LLC, as administrative agent (the “New Administrative Agent”). The New Credit Facility consists of a $10 million revolving loan facility and a $20 million term loan facility.
The New Credit Facility has two significant covenants, which require us to maintain (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00. These financial covenants are subject to customary cure rights. We were in compliance with all applicable financial covenants under the New Credit Facility as of December 31, 2020.
The New Credit Facility replaced the Company’s Prior Credit Facility, dated as of February 10, 2017, as amended which was terminated effective November 30, 2020 and otherwise would have matured on April 1, 2021. The company used the $20.0 million term loan proceeds to repay the $12.0 million outstanding on the Prior Credit Facility on November 30, 2020.
We have approximately $10.0 million of available borrowing capacity under the New Credit Facility line of credit at December 31, 2020.
See “Note 11 — Long-Term Debt” to the accompanying consolidated financial statements included in Item 8 of this report for additional discussion of the Company’s debt during 2020 and 2019.
Valuation Allowance
Upon emergence from bankruptcy and the application of fresh start accounting in 2016, our tax basis in property, plant, and equipment exceeded the book carrying value of our assets. Additionally, we had significant U.S. federal net operating losses remaining after the attribute reduction caused by the restructuring transactions. As such, the successor Company had significant deferred tax assets to consume upon emergence. We considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be fully realized and established a valuation allowance against our net deferred tax asset upon emergence and maintained the valuation allowance for the subsequent periods through December 31, 2020.
We continue to closely monitor all available evidence in considering whether to maintain a valuation allowance on our net deferred tax asset. Factors considered include, but are not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, our historical earnings and the prospects of future earnings. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.
In determining whether to maintain the valuation allowance at December 31, 2020, we concluded that the objectively verifiable negative evidence of the presumption of cumulative negative earnings upon emergence and actual cumulative negative earnings for the Successor Company period ending December 31, 2020, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, we have not changed our judgment regarding the need for a full valuation allowance against our net deferred tax asset for the period ending December 31, 2020.
See “Note 14 — Income Taxes” to the accompanying consolidated financial statements for additional discussion of income tax related matters.
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Critical Accounting Policies and Estimates
The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the Company’s financial statements requires management to make assumptions and prepare estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Estimates are based on historical experience and various other assumptions believed to be reasonable; however, actual results may differ significantly. The Company’s critical accounting policies and additional information on significant estimates are discussed below. See “Note 1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report for additional discussion of significant accounting policies.
Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates and issue long-term debt that contains embedded derivatives.
The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company’s earnings may fluctuate significantly as a result of changes in fair value. Derivative assets and liabilities are netted whenever a legally enforceable master netting agreement exists with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows.
Fair values of the substantial majority of the Company’s commodity derivative financial instruments are determined primarily by using discounted cash flow calculations or option pricing models, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be corroborated from active markets. Estimates of future prices are based upon published forward commodity price curves for oil and natural gas instruments. Valuations also incorporate adjustments for the nonperformance risk of the Company or its counterparties, as applicable.
Proved Reserves. Approximately 91.5% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2020. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company’s control. Estimating reserves is a complex process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data. The accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2020 and 2019, the Company revised its proved reserves from prior years’ reports by approximately (44.8) MMBoe and (58.5) MMBoe, respectively, due to decreases in SEC prices used to value reserves at the end of the applicable period, production performance indicating more (or less) reserves in place, larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings within the original field boundaries. Estimates of proved reserves are key components of the Company’s financial estimates used to determine depreciation and depletion on oil and natural gas properties and its full cost ceiling limitation. Future revisions to estimates of proved reserves may be material and could materially affect the Company’s future depreciation, depletion and impairment expenses.
Method of Accounting for Oil and Natural Gas Properties. The Company’s business is subject to accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. The Company uses the full cost method to account for its oil and natural gas properties. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Exploration and development costs include dry well costs,
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geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil, natural gas and NGL reserves. Amortization of oil and natural gas properties is calculated using the unit-of-production method based on estimated proved oil, natural gas and NGL reserves. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center, unless it results in a greater than 10% change to the depletion rate.
Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion and impairment of oil and natural gas properties are generally calculated on a well by well, lease or field basis versus the aggregated “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method. As a result, the Company’s financial statements will differ from companies that apply the successful efforts method since the Company will generally reflect a higher level of capitalized costs as well as a higher oil and natural gas depreciation and depletion rate, and the Company will not have exploration expenses that successful efforts companies frequently have.
Impairment of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of oil and natural gas properties and electrical infrastructure costs, net of accumulated depreciation, depletion and impairment, less related deferred income taxes, may not exceed an amount equal to the ceiling limitation. The Company calculates its full cost ceiling limitation using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down cannot be reversed at a later date. The Company recorded full cost ceiling impairment of $218.4 million for the year ended December 31, 2020 and $409.6 million for the year ended December 31, 2019. See “—Consolidated Results of Operations” for additional discussion of full cost ceiling impairments.
Unproved Properties. The balance of unproved properties consists primarily of costs to acquire unproved acreage. These costs are initially excluded from the Company’s amortization base until it is known whether proved reserves will or will not be assigned to the property. The Company assesses all properties, on an individual basis or as a group if properties are individually insignificant, classified as unproved on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. For leases that do not have existing production that would otherwise extend the lease term, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a three to five year period from the original lease date. For leases that are held by production, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a 10-year period from the original lease date.
Property, Plant and Equipment, Net. Other capitalized costs including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the amortized fair value established on the 2016 bankruptcy emergence date. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in operations. The carrying value of property and equipment is reviewed for possible impairment annually or whenever events or changes in circumstances indicate that the carrying value of such asset or asset group may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If an asset or asset group is determined to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. The Company may also determine fair value by using the present value of estimated future cash inflows and/or outflows, or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Changes in such estimates could cause the Company to reduce the carrying value of property and equipment.
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See “—Consolidated Results of Operations” and “Note 9—Impairment” to the Company’s accompanying consolidated financial statements in Item 8 of this report for a discussion of the Company’s impairments.
Asset Retirement Obligations. Asset retirement obligations represent the estimate of fair value of the cost to plug, abandon and remediate the Company’s wells at the end of their productive lives, in accordance with applicable federal and state laws. The Company estimates the fair value of an asset’s retirement obligation in the period in which the liability is incurred (at the time the wells are drilled or acquired). Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. The Company employs a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions and requires significant judgment, including an inflation rate, its credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third-party quotes and current actual costs. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.
Revenue Recognition. Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. The Company deducts transportation costs from oil, natural gas and NGL revenues. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production, ad valorem and other taxes in the consolidated statements of operations. See "Note 16—Revenues" to the Company's accompanying consolidated financial statements in Item 8 of this report for further information on the Company's accounting policies related to revenues.
Income Taxes. Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns. As of December 31, 2020, the Company had a full valuation allowance against its net deferred tax asset. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.
New Accounting Pronouncements. For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report.
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