Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.
Overview
We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas. As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive economics.
At December 31, 2021, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), using Securities and Exchange Commission (SEC) prices for crude oil and natural gas, which are based on preceding 12-month first day of the month average prices of West Texas Intermediate (WTI) crude oil spot price of $66.55 per Bbl and Henry Hub natural gas spot price of $3.60 per MMBtu, were approximately 95.9 MMBoe, consisting of 58.7 MMBbls of oil, 16.3 MMBbls of natural gas liquids, and 125.0 Bcf of natural gas. Approximately 44% of our proved reserves were classified as proved developed as of December 31, 2021. We maintain operational control of 99.9% of our proved reserves. Substantially all of our proved reserves and production at December 31, 2021 are associated with our Delaware Basin properties.
Our total operating revenues for the year ended December 31, 2021 were approximately $285.2 million, compared to total operating revenues for the year ended December 31, 2020 of approximately $148.3 million. The increase in revenues is primarily attributable to an approximate $24.14 per Boe increase in average realized prices (excluding the effects of hedging arrangements). Full year 2021 production averaged 16,241 Boe/d compared to average daily production of 16,858 Boe/d for 2020. Average daily oil and natural gas production was impacted by the temporary shut-in of production amounting to approximately 300 Boe/d and 1,300 Boe/d for the year ended December 31, 2021 and 2020, respectively. In February 2021, we temporarily shut-in production due to inclement weather. In May and June 2020, we temporarily shut-in production in response to historically low commodity prices. Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs.
Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.
In 2021, we spent approximately $52.6 million on oil and gas capital expenditures. In early 2021 and at the end of 2021, we ran one operated rig in the Delaware Basin. We drilled and cased 2.0 gross (2.0 net) operated wells, completed 6.0 gross (6.0 net) operated wells, and put online 6.0 gross (6.0 net) operated wells during the year.
We expect to spend approximately $130.0 million to $150.0 million on capital expenditures during 2022. Overall, we currently plan to drill 12 gross operated wells during the year, complete 9 to 13 gross operated wells, and bring 8 to 12 gross operated wells on production. Our 2022 capital budget currently contemplates running one operated rig in the Delaware Basin during the year. We continuously monitor changes in market conditions and adapt our operational plans
40
Table of Contents
as necessary in order to maintain financial flexibility, preserve core acreage and meet contractual obligations, and therefore our capital budget is subject to change.
We expect to fund our budgeted 2022 capital expenditures with cash and cash equivalents on hand from the funding of the Term Loan Agreement and cash flows from operations. In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending. However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.
Oil and natural gas prices are inherently volatile and sustained lower commodity prices could have a material impact upon our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the first-day-of-the-month average for the 12-months ended March 31, 2022 of the WTI crude oil spot price of $75.28 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended March 31, 2022 of the Henry Hub natural gas price of $4.09 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation would not have generated an additional impairment at December 31, 2021, holding all other inputs and factors constant. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
Recent Developments
Risk and Uncertainties
We are continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on our business, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including implementing various measures to ensure the continued operation of our business in a safe and secure manner. In 2020, COVID-19 and governmental actions to contain the pandemic contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war involving the Organization of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels. Although OPEC and Russia subsequently agreed to reduce production, downward pressure on prices continued for several months, particularly given concerns over the impacts of the current economic downturn on demand. As a consequence, beginning March 2020, we realized lower revenue as a result of commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year. Additionally in 2020, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.
During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices. Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions. However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors. As a consequence, we are unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020. Furthermore, the health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions remain concerns and cannot be predicted, nor can the impact on our customers, vendors and contractors. Any material effect on these parties could adversely impact us. These and other factors could affect our operations, earnings and cash flows and could cause our results to not be comparable to those of the same period in previous years. The results presented in this Form
41
Table of Contents
10-K are not necessarily indicative of future operating results. For further information regarding the actual and potential impacts of COVID-19 on us, see “Risk Factors” in Item 1A of this Annual Report on Form 10-K.
Term Loan Credit Facility
On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower), entered into an Amended and Restated Senior Secured Credit Agreement (Term Loan Agreement) with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders. The Term Loan Agreement amends and restates in its entirety our Senior Credit Agreement as discussed below. Pursuant to the Term Loan Agreement, the lenders have agreed to loan us (i) $200.0 million, which funded on November 24, 2021 and was partially used to refinance all amounts owed under the Senior Credit Agreement; (ii) up to $20.0 million, available to be drawn up to 18 months from November 24, 2021, subject to the satisfaction of certain conditions; and (iii) up to $15.0 million, which amount will be available to be drawn from the date certain wells included in the approved plan of development are deemed producing, subject to the satisfaction of certain conditions. An additional $5.0 million is available for the issuance of letters of credit. The maturity date of the Term Loan Agreement is November 24, 2025. Until such maturity date, borrowings under the Term Loan Agreement shall bear interest at a rate per annum equal to LIBOR (or another applicable reference rate, as determined pursuant to the provisions of the Term Loan Agreement) plus an applicable margin of 7.00%. See Item 8. Consolidated Financial Statements and Supplementary Data —Note 6, “Debt” for additional information on the Term Loan Agreement.
Senior Revolving Credit Facility
On November 24, 2021, our Senior Secured Revolving Credit Agreement (Senior Credit Agreement) was amended and restated in its entirety by the Term Loan Agreement. Borrowings outstanding under the Senior Credit Agreement were repaid with proceeds from the Term Loan Agreement resulting in a charge of $0.1 million presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021.
On September 24, 2021, we entered into the Fifth Amendment to Senior Secured Revolving Credit Agreement (the Fifth Amendment) which, among other things, modified the limits on swap agreements so as not to exceed, (i) from the period of the Fifth Amendment effective date through December 31, 2021, the percentage of the reasonably anticipated hydrocarbon production from proved developed producing reserves during such period hedged pursuant to secured swap agreements in place as of the Fifth Amendment effective date; (ii) for the fiscal year ending December 31, 2022, the greater of (a) the proved developed producing reserves during such fiscal year hedged pursuant to secured swap agreements in place as of the Fifth Amendment effective date and (b) 85% of the proved developed producing reserves during such fiscal year; and (iii) for the fiscal years ending December 31, 2023, December 31, 2024 and December 31, 2025, swap agreements not to exceed 85%, 70% and 60% of the proved developed producing reserves, respectively, during each fiscal year.
On May 10, 2021, we entered into the Fourth Amendment to Senior Secured Revolving Credit Agreement (the Fourth Amendment) which reduced the borrowing base to $185.0 million effective June 1, 2021 and further reduced the borrowing base to $175.0 million effective September 1, 2021. The Fourth Amendment also, among other things, (i) increased interest margins to 2.00% to 3.00% for ABR-based loans and 3.00% to 4.00% for Eurodollar-based loans, (ii) amended the covenant relating to the minimum mortgaged total value of proved borrowing base properties to increase the value from 90% to 95%, (iii) provided for direct reductions in the borrowing base in the event of asset dispositions in excess of $1.0 million per fiscal year or swap terminations and (iv) revised certain covenants and covenant-related baskets including, but not limited to, adding covenants prohibiting the designation of unrestricted subsidiaries and requiring prior consent from the lenders regarding asset dispositions or swap terminations in excess of the greater of $7.5 million or 3.5% of the then effective borrowing base.
Paycheck Protection Program Loan
Effective August 13, 2021, the principal amount of our promissory note (the PPP Loan) under the Paycheck Protection Program of the Coronavirus Aid, Relief and Economic Security Act (the CARES Act) was reduced from $2.2 million to $0.2 million by the U.S. Small Business Administration (SBA). We applied for forgiveness of the amount due
42
Table of Contents
on the PPP Loan based on the use of the loan proceeds on eligible expenses in accordance with the terms of the CARES Act. We recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $2.1 million. The gain is presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021.
Employee Retention Credit
The CARES Act included, among other things, provisions relating to refundable payroll tax credits (the Employee Retention Credit or ERC). As provided for in the CARES Act and subsequent legislation which modified and extended the provisions included therein, the ERC allows for a refundable tax credit against certain employment taxes equal to 50% of the first $10,000 in qualified wages paid to each employee after March 12, 2020 and through December 31, 2020 and 70% of the first $10,000 in qualified wages paid to each employee, per calendar quarter, after December 31, 2020 through September 30, 2021. During the year ended December 31, 2021, we determined that the qualifications for the Employee Retention Credit were met and filed the corresponding applications for the applicable 2020 and 2021 periods. We recognized an approximate $0.7 million Employee Retention Credit during the year ended December 31, 2021, with approximately $0.5 million recorded to “General and administrative” and approximately $0.2 million recorded to “Lease operating” in the consolidated statements of operations.
Capital Resources and Liquidity
In March 2020, the World Health Organization declared the outbreak of COVID-19 a pandemic. In 2020, the COVID - 19 outbreak and associated government restrictions significantly impacted economic activity and markets and dramatically demand for oil and natural gas at the same time that supply was maintained at high levels due to a price and market share war involving the OPEC/Saudi Arabia and Russia, all of which adversely impacted the prices we received for our production. As a consequence, beginning in March 2020, we realized lower revenue as a result of these commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year. Additionally in 2020, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.
During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices. Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions. However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors. As a consequence, we are unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020. Actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the U.S. or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from current efforts to contain the COVID-19 coronavirus or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production or adversely impacting our ability to comply with covenants in our Term Loan Agreement. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our Term Loan Agreement.
We expect to spend approximately $130.0 million to $150.0 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs, during 2022. Additionally, from time to time, we enter into commitments that may require us to incur material expenditures in the future. Included in our 2022 capital expenditures budget is $2.6 million associated with an active drilling rig commitment. We have a minimum volume commitment with
43
Table of Contents
a third party for the treating of sour gas production through June 30, 2022. The future payments associated with the minimum volume commitment are approximately $4.8 million. These capital spending requirements and commitments are expected to be funded with cash and cash equivalents on hand from the funding of our Term Loan Agreement and cash flows from operations. Amounts borrowed under our Term Loan Agreement bear interest at LIBOR plus an applicable margin of 7.00% and will mature on November 24, 2025. At December 31, 2021, we had $46.9 million of cash and cash equivalents, $200.0 million of indebtedness outstanding, approximately $0.3 million letters of credit outstanding and $35.0 million in delayed draw term loans available to be drawn under our Term Loan Agreement, subject to the satisfaction of certain conditions defined in the agreement. We are required to make scheduled amortization payments in the aggregate amount of $120.0 million from the fiscal quarter ending March 31, 2023 through the fiscal quarter ending September 30, 2025. In addition, we may be required to make mandatory prepayments of the loans under the Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, and with excess cash on hand in excess of certain maximum levels. For each fiscal quarter after January 1, 2023, we shall make mandatory prepayments when the Consolidated Cash Balance, as defined in the Term Loan Agreement, exceeds $20.0 million. Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance.
The Term Loan Agreement contains certain financial covenants, including maintenance of (i) an Asset Coverage Ratio (as defined in the Term Loan Agreement) of not less than (A) 1.50 to 1.00 as of December 31, 2021 and March 31, 2022, (B) 1.60 to 1.00 as of June 30, 2022, (C) 1.70 to 1.00 as of September 30, 2022, and (D) 1.80 to 1.00 as of December 31, 2022 and each fiscal quarter thereafter, (ii) a Total Net Leverage Ratio (as defined in the Term Loan Agreement) of not greater than (A) 3.25 to 1.00 as of December 31, 2021 through and including June 30, 2022, (B) 3.00 to 1.00 as of September 30, 2022 and December 31, 2022, (C) 2.75 to 1.00 as of March 31, 2023, and (D) 2.50 to 1.00 as of each fiscal quarter thereafter, and (iii) a Current Ratio (as defined in the Term Loan Agreement) of not less than 1.00:1.00, each determined as of the last day of any fiscal quarter period.
Changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can affect our ability to comply with the covenants under our Term Loan Agreement. As a consequence, we endeavor to anticipate potential covenant compliance issues and work with our lenders to address any such issues ahead of time.
We have periodically, including as recently as October 2020, obtained waivers or amendments to the financial covenants under our revolving credit agreements in circumstances where we anticipated that it might be challenging for us to comply with the financial covenants for a particular period of time. For instance, depressed oil and natural gas prices during 2020 and our decision to temporarily shut-in a portion of our production in response to market conditions adversely impacted our cash flows, which, combined with cash requirements associated with capital-intensive oil and gas development projects undertaken in late 2019 and early 2020, led to challenges in our compliance with the Current Ratio under the Senior Credit Agreement for the fiscal quarter ended June 30, 2020. Thus, on July 31, 2020, we secured a waiver in which the lenders consented to waive maintenance of the Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020. In conjunction with the fall 2020 borrowing base redetermination process under the Senior Credit Agreement, and due to a decline in the value associated with our derivative contracts, we pursued additional relief from our lenders in regards to the Current Ratio. On October 29, 2020, in the Third Amendment to the Senior Credit Agreement, the lenders waived maintenance with the Current Ratio for the fiscal quarter ending September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ended December 31, 2021. The Senior Credit Agreement was amended and restated by the Term Loan Agreement in November 2021.
Similarly, in prior years, we have also obtained waivers and amendments for other financial covenant violations. For instance, our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin. Our drilling activities once we acquired these assets required significant capital expenditure outlays to replenish production and related EBITDA from the divested producing properties. These and other factors adversely impacted our ability to comply with our debt covenants under the predecessor credit agreement by reducing our production, reserves and EBITDA on a current and a pro forma historical basis, while making us more susceptible to fluctuations in performance and compliance more challenging. In addition, we encountered certain
44
Table of Contents
operational difficulties that impacted our ability to comply, including elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells and limited and expensive treatment and transportation options. Severance payments to executives in 2019 also impacted our ability to comply with our financial covenants.
While we have largely been successful in obtaining modifications of our covenants as needed, there can be no assurance that we will be successful in the future. In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business. Even if successful, alternative sources of financing could prove more expensive than borrowings under our Term Loan Agreement.
When commodity prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge are less than our expected production, vary from period to period based on our view of current and future market conditions, remain consistent with the requirements in effect under our Term Loan Agreement and extend, on a rolling basis, for the next four years. These limitations result in our liquidity being susceptible to commodity price declines. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.
Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We strive to maintain financial flexibility while pursuing our drilling plans and may access capital markets, pursue joint ventures, sell assets and engage in other transactions as necessary to, among other things, maintain sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage. Our ability to complete such transactions and maintain or increase our liquidity is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.
Cash Flow
In 2021, operating cash flows and net borrowings under our credit agreements funded our capital expenditures program. See “ Results of Operations ” for a review of the impact of prices and volumes on operating revenues.
Net increase (decrease) in cash, cash equivalents and restricted cash is summarized as follows (in thousands):
Years Ended December 31,
2021
2020
Cash flows provided by (used in) operating activities
$
68,572
$
50,197
Cash flows provided by (used in) investing activities
(51,913)
(72,354)
Cash flows provided by (used in) financing activities
27,405
16,177
Net increase (decrease) in cash, cash equivalents and restricted cash
$
44,064
$
(5,980)
Operating Activities. Net cash flows provided by operating activities for the year ended December 31, 2021 and 2020 were $68.6 million and $50.2 million, respectively.
45
Table of Contents
Operating cash flows for the year ended December 31, 2021 increased from the prior year due an approximate $24.14 per Boe average realized price increase which contributed to higher total operating revenues in 2021 partially offset by realized losses from derivative contracts incurred in 2021 as a result of increased commodity prices.
Operating cash flows for the year ended December 31, 2020 increased from the prior year due to decreases in our operating expenses associated with our focus on efficiencies and cost savings and a decrease in interest expense associated with lower outstanding debt due to our chapter 11 bankruptcy. In addition, realized gains from derivative contracts were higher in the year ended December 31, 2020, which included the early termination of certain derivative contracts. During the year ended December 31, 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $22.9 million during the period. These increases to operating cash flows in 2020 were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices and lower production volumes than the comparable prior year period.
Investing Activities. Net cash flows used in investing activities for the year ended December 31, 2021 and 2020 were approximately $51.9 million and $72.4 million, respectively.
During the year ended December 31, 2021, we spent $52.6 million on oil and natural gas capital expenditures, of which $42.9 million related to drilling and completion costs and $6.8 million related to the development of our treating equipment and gathering support infrastructure. We received $0.9 million in proceeds from the sale of oil and natural gas properties.
During the year ended December 31, 2020, we spent $101.8 million on oil and natural gas capital expenditures, of which $65.1 million related to drilling and completion costs and $33.9 million related to the development of our treating equipment and gathering support infrastructure. We received $29.0 million in proceeds from the sale of oil and natural gas properties, primarily from the sale of the northern assets in our West Quito area in December 2020. In addition, we received $0.5 million in insurance proceeds associated with a casualty loss on our support infrastructure.
Financing Activities. Net cash flows provided by financing activities for the year ended December 31, 2021 and 2020 were approximately $27.4 million and $16.2 million, respectively.
During the year ended December 31, 2021, we borrowed $200.0 million under the Term Loan Agreement and paid in cash $14.2 million in debt issuance costs associated with the loan. A portion of the funds received from the Term Loan Agreement were used to refinance all amounts owed under the Senior Credit Agreement.
During the year ended December 31, 2020, net borrowings of $14.0 million under our Senior Credit Agreement were used to fund our drilling and completions program and the development of our treating equipment and gathering support facilities. We also borrowed $2.2 million under the PPP Loan to fund payroll costs, rent and utilities.
Term Loan Credit Facility
On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into the Term Loan Agreement with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders. The Term Loan Agreement amends and restates in its entirety our Senior Credit Agreement as discussed below. Pursuant to the Term Loan Agreement, the lenders have agreed to loan us (i) $200.0 million, which funded on November 24, 2021 and was partially used to refinance all amounts owed under the Senior Credit Agreement; (ii) up to $20.0 million, available to be drawn up to 18 months from November 24, 2021, subject to the satisfaction of certain conditions; and (iii) up to $15.0 million, which amount will be available to be drawn from the date certain wells included in the approved plan of development (APOD) are deemed producing APOD wells until up to 18 months after November 24, 2021, subject to the satisfaction of certain conditions. An additional $5.0 million is available for the issuance of letters of credit. The maturity date of the Term Loan Agreement is November 24, 2025. Until such maturity date, borrowings under the Term Loan Agreement shall bear interest at a rate per annum equal to LIBOR (or another applicable reference rate, as determined pursuant to the provisions of the Term Loan Agreement) plus an applicable margin of 7.00%.
46
Table of Contents
We may be required to make mandatory prepayments of the loans under the Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, and with excess cash on hand in excess of certain maximum levels. For each fiscal quarter after January 1, 2023, we shall make mandatory prepayments when the Consolidated Cash Balance, as defined in the Term Loan Agreement, exceeds $20.0 million. Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance. We are required to make scheduled amortization payments in the aggregate amount of $120.0 million from the fiscal quarter ending March 31, 2023 through the fiscal quarter ending September 30, 2025. Amounts outstanding under the Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and of the equity interests of the Borrower held by us. As part of the Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries.
The Term Loan Agreement also contains certain financial covenants, including the maintenance of (i) an Asset Coverage Ratio (as defined in the Term Loan Agreement) of not less than (A) 1.50 to 1.00 as of December 31, 2021 and March 31, 2022, (B) 1.60 to 1.00 as of June 30, 2022, (C) 1.70 to 1.00 as of September 30, 2022, and (D) 1.80 to 1.00 as of December 31, 2022 and each fiscal quarter thereafter, (ii) a Total Net Leverage Ratio (as defined in the Term Loan Agreement) of not greater than (A) 3.25 to 1.00 as of December 31, 2021 through and including June 30, 2022, (B) 3.00 to 1.00 as of September 30, 2022 and December 31, 2022, (C) 2.75 to 1.00 as of March 31, 2023, and (D) 2.50 to 1.00 as of each fiscal quarter thereafter, and (iii) a Current Ratio (as defined in the Term Loan Agreement) of not less than 1.00 to 1.00, each determined as of the last day of any fiscal quarter period. As of December 31, 2021, we were in compliance with the financial covenants under the Term Loan Agreement.
The Term Loan Agreement also contains an APOD for our Monument Draw acreage through the drilling and completion of certain wells. The Term Loan Agreement contains a proved developed producing production test and an APOD economic test which we must maintain compliance with otherwise, subject to any available remedies or waivers, we are required to immediately cease making expenditures in respect of the approved plan of development other than any expenditures deemed necessary by us in respect of no more than six additional approved plan of development wells.
The Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.
See Item 8. Consolidated Financial Statements and Supplementary Data– Note 6, “Debt” for additional information on the Term Loan Agreement.
Paycheck Protection Program Loan
On April 16, 2020, we entered into the PPP Loan for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the SBA. Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0% per annum and has a maturity date of April 16, 2022. As long as we made a timely application of forgiveness to the SBA, we were not required to make any payments under the PPP Loan until the forgiveness amount was communicated to us by the SBA. We applied for forgiveness of the amount due on the PPP Loan based on the use of the loan proceeds on eligible expenses in accordance with the terms of the CARES Act. Effective August 13, 2021, the principal amount of our PPP Loan was reduced to $0.2 million by the SBA and we recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $2.1 million. The gain is presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021.
The PPP Loan contains certain events of default including non-payment, breach of representations and warranties, cross-defaults to other loans with the lender or to material indebtedness, voluntary or involuntary bankruptcy, judgments and change in control.
47
Table of Contents
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8. Consolidated Financial Statements and Supplementary Data —Note 1, “ Summary of Significant Events and Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.
Oil and Natural Gas Activities
Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available-successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using the unweighted arithmetic average of the first day of the month for each of the 12-month prices for oil and natural gas within the period, holding prices and costs constant and applying a 10% discount rate.
Full Cost Method
We use the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized into a cost center (the amortization base or full cost pool). Such amounts include the cost of drilling and equipping productive wells, treating equipment and gathering support facilities costs, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.
Proved Oil and Natural Gas Reserves
Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of (i) the quality and quantity of
48
Table of Contents
available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.
Our estimated proved reserves for the years ended December 31, 2021, 2020 and 2019 were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited). ”
Depletion Expense
Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2021, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.37 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.40 per Boe.
Full Cost Ceiling Test Limitation
Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and could result in lower amortization expense in future periods. The present value of our estimated proved reserves (discounted at 10%) is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of our oil and natural gas properties could occur in the future.
If the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ended December 31, 2021 had been 10% lower while all other factors remained constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced by approximately $182.9 million and would not have generated a full cost ceiling impairment.
Future Development Costs
Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production facility, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. At December 31, 2021, a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.27 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.27 per Boe.
49
Table of Contents
Accounting for Derivative Instruments and Hedging Activities
We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, in accordance with our policy, we may hedge a portion of our forecasted oil and natural gas production. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.
Income Taxes
Our provision for taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.
In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. Based upon the evaluation of available evidence we recorded a decrease of $57.8 million to our valuation allowance as a result of increases to deferred tax assets for deferred deductions and net operating losses offset by the write-off of deferred tax assets for oil and gas properties and other deferred tax assets during 2021. A valuation allowance of $431.7 million has been applied against our deferred tax assets as of December 31, 2021.
We follow ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.
50
Table of Contents
Comparison of Results of Operations
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
We reported a net loss of $28.3 million and $229.7 million for the year ended December 31, 2021 and 2020, respectively. The table included below sets forth financial information for the periods presented.
Years Ended
December 31,
In thousands (except per unit and per Boe amounts)
2021
2020
Change
Net income (loss)
$
(28,317)
$
(229,707)
$
201,390
Operating revenues:
Oil
213,512
125,985
87,527
Natural gas
35,248
5,818
29,430
Natural gas liquids
35,394
14,972
20,422
Other
1,051
1,514
(463)
Operating expenses:
Production:
Lease operating
43,977
42,106
1,871
Workover and other
3,224
3,709
(485)
Taxes other than income
12,312
10,056
2,256
Gathering and other
60,396
56,016
4,380
Restructuring
—
2,580
(2,580)
General and administrative:
General and administrative
14,504
15,878
(1,374)
Stock-based compensation
2,010
2,578
(568)
Depletion, depreciation and accretion:
Depletion – Full cost
44,613
60,543
(15,930)
Depreciation – Other
318
925
(607)
Accretion expense
477
585
(108)
Full cost ceiling impairment
—
215,145
(215,145)
Other income (expenses):
Net gain (loss) on derivative contracts
(125,619)
38,759
(164,378)
Interest expense and other
(8,018)
(6,634)
(1,384)
Gain (loss) on extinguishment of debt
1,946
—
1,946
Production:
Crude oil – MBbls
3,196
3,446
(250)
Natural gas – MMcf
9,447
8,769
678
Natural gas liquids – MBbls
1,157
1,262
(105)
Total MBoe (1)
5,928
6,170
(242)
Average daily production – Boe (1)
16,241
16,858
(617)
Average price per unit (2) :
Crude oil price - Bbl
$
66.81
$
36.56
$
30.25
Natural gas price - Mcf
3.73
0.66
3.07
Natural gas liquids price - Bbl
30.59
11.86
18.73
Total per Boe (1)
47.93
23.79
24.14
Average cost per Boe:
Production:
Lease operating
$
7.42
$
6.82
$
0.60
Workover and other
0.54
0.60
(0.06)
Taxes other than income
2.08
1.63
0.45
Gathering and other
10.19
9.08
1.11
Restructuring
—
0.42
(0.42)
General and administrative:
General and administrative
2.45
2.57
(0.12)
Stock-based compensation
0.34
0.42
(0.08)
Depletion
7.53
9.81
(2.28)
(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency. This is an energy content correlation and does not reflect the value or price relationship between the commodities.
(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.
51
Table of Contents
Oil, natural gas and natural gas liquids revenues were $284.2 million and $146.8 million for the year ended December 31, 2021 and 2020, respectively. The increase in revenue is primarily attributable to an approximate $24.14 per Boe increase in our average realized prices (excluding the effects of hedging arrangements). The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors. For the year ended December 31, 2021 and 2020, production averaged 16,241 Boe/d and 16,858 Boe/d, respectively. Average daily oil and natural gas production was impacted by the temporary shut-in of production amounting to approximately 300 Boe/d and 1,300 Boe/d in 2021 and 2020, respectively. In February 2021, we temporarily shut-in production due to inclement weather. In May and June 2020, we temporarily shut-in production in response to historically low commodity prices. Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs.
Lease operating expenses were $44.0 million and $42.1 million for the year ended December 31, 2021 and 2020, respectively. On a per unit basis, lease operating expenses were $7.42 per Boe and $6.82 per Boe for the year ended December 31, 2021 and 2020, respectively. The increase in lease operating expenses in 2021 results from a market increase associated with maintenance, power and chemical costs partially offset by decreased salt water disposal costs due to lower production volumes and less produced water.
Workover and other expenses were $3.2 million and $3.7 million for the year ended December 31, 2021 and 2020, respectively. On a per unit basis, workover and other expenses were $0.54 per Boe and $0.60 per Boe for the year ended December 31, 2021 and 2020, respectively. The decreased workover and other expenses in 2021 relate to preventative operational measures previously undertaken to mitigate potential future failures in producing wells.
Taxes other than income were $12.3 million and $10.1 million for the year ended December 31, 2021 and 2020, respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.08 per Boe and $1.63 per Boe for the year ended December 31, 2021 and 2020, respectively.
Gathering and other expenses were $60.4 million and $56.0 million for the year ended December 31, 2021 and 2020, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure. Approximately $22.7 million and $13.9 million for the year ended December 31, 2021 and 2020, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Gathering and marketing fees increased in 2021 as we marketed higher quantities of sour gas production to third parties in the current year period. Approximately $37.7 million and $38.7 million for the year ended December 31, 2021 and 2020, respectively, relate to operating expenses on our treating equipment and gathering support facilities. The decrease in treating equipment and gathering support facilities expenses in 2021 results from lower operating expenses associated with our treating equipment, as fewer sour gas production volumes were processed through our hydrogen sulfide treating plant in the current year period, which were partially offset by higher electricity and buy back fuel costs incurred as a result of inclement weather in February 2021 and higher chemical costs to improve the quality of treated oil. Also included are $3.4 million of rig stacking charges for the year ended December 31, 2020.
Restructuring expense was approximately $2.6 million for the year ended December 31, 2020. During the year ended December 31, 2020, we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our workforce due to efforts to improve efficiencies and go forward costs. In May 2020, in furtherance of the consolidation into one corporate office, we exercised a one-time early termination option under the lease agreement for our office space in Denver, Colorado.
General and administrative expense was $14.5 million and $15.9 million for the year ended December 31, 2021 and 2020, respectively. The decrease in general and administrative expense in the current year period is associated with a decrease in professional fees and information technology expenses, as well as the Employee Retention Credit. This decrease is partially offset by lower 2020 payroll costs, as the 2020 period included a $1.6 million reduction to general and administrative expenses related to our change in estimate of discretionary cash incentives. In late March 2020, due to changes in market conditions and decreased commodity prices, we determined that previously accrued discretionary cash incentives related to 2019 would not be paid, causing a $1.6 million reduction to general and administrative
52
Table of Contents
expenses in the 2020 period. On a per unit basis, general and administrative expense were $2.45 per Boe and $2.57 per Boe for the year ended December 31, 2021 and 2020, respectively.
Stock-based compensation expense was $2.0 million and $2.6 million for the year ended December 31, 2021 and 2020, respectively. Stock-based compensation expense decreased in the current year due to restricted stock units vesting during the first quarter of 2021.
Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $44.6 million and $60.5 million for the year ended December 31, 2021 and 2020, respectively. On a per unit basis, depletion expense was $7.53 per Boe and $9.81 per Boe for the year ended December 31, 2021 and 2020, respectively. The depletable base of our unit of production calculation was reduced by the full cost ceiling test impairments incurred in 2020 and increased by future development costs associated with PUD reserve additions. We also experienced an increase in proved reserve volumes, primarily from PUD reserve additions, which resulted in a decrease to our depletion rate in 2021 as compared to 2020.
Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling”, based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. During 2020, the net book value of our oil and gas properties at June 30, September 30 and December 31 exceeded the ceiling amount and we recorded full cost ceiling test impairments before income taxes of $60.1 million, $128.3 million and $26.7 million, respectively, for the periods. The ceiling test impairments during 2020 were primarily driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation. Additionally, during the three months ended September 30, 2020, the transfer of $23.6 million of unevaluated property costs to the full cost pool due to our intent to focus available capital on Monument Draw also contributed to the impairment recorded for the period. During the three months ended December 31, 2020, proved undeveloped reserves additions as a result of changes to our five year development plan partially offset the impact of the average price decline on the impairment for the period.
We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. At December 31, 2021, we had a $3.9 million derivative asset, $1.4 million of which was classified as current, and we had a $65.5 million derivative liability, $58.3 million of which was classified as current. We recorded a net derivative loss of $125.6 million ($47.7 million net unrealized loss and $77.9 million net realized loss on settled contracts) for the year ended December 31, 2021. We recorded a net derivative gain of $38.8 million ($6.1 million net unrealized loss and $44.9 million net realized gain on settled and early terminated contracts) for the year ended December 31, 2020. During 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $22.9 million, which were included in the $44.9 million net realized gains for the year.
Interest expense and other was $8.0 million and $6.6 million for the year ended December 31, 2021 and 2020, respectively. Interest expense and other increased in the current period due to interest and the amortization of debt issuance costs associated with our Term Loan Agreement.
During the year ended December 31, 2021, we recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $2.1 million. We applied for forgiveness of the amount due on the PPP Loan based on the use of the loan proceeds on eligible expenses in accordance with the terms of the CARES Act. Effective August 13, 2021, the principal amount of our PPP Loan was reduced from $2.2 million to $0.2 million by the SBA. This gain was partially offset by a $0.1 million extinguishment loss resulting from the refinancing of our Senior Credit Agreement.
53
Table of Contents
Recently Issued Accounting Pronouncements
We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data —Note 1, “ Summary of Significant Events and Accounting Policies .”