Item 2. Management’s Discussion and Analysis
ITEM 2. 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 for the three months ended March 31, 2022 and 2021 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2021.
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. For more information, see “ Special note regarding forward-looking statements .”
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 long-term economics.
Our total operating revenues for the first three months of 2022 and 2021 were $81.6 million and $55.5 million, respectively. The increase in revenues is primarily attributable to an approximate $18.42 per Boe increase in average realized prices (excluding the effects of hedging arrangements). During the first three months of 2022, production averaged 14,767 Boe/d compared to average production of 14,333 Boe/d during the first three months of 2021. In February 2021, we temporarily shut-in production due to inclement weather. The estimated decrease in average daily oil and natural gas production associated with this temporary shut-in was approximately 1,300 Boe/d in the first three months of 2021. Current year production was impacted by natural production declines on our existing producing wells. We last brought new producing wells online in June 2021. For the three months ended March 31, 2022, we drilled and cased 3.0 gross (3.0 net) operated wells, completed zero gross and net operated wells, and put online zero gross and net operated wells.
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, developing and producing oil and natural gas reserves at economical costs are critical to our long-term success.
Oil and natural gas prices are inherently volatile and sustained lower commodity prices could result in impairment charges under 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 crude oil price for April 2022 of $99.33 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test calculation would not have generated an impairment, 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.
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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 economic downturn on demand. As a consequence, beginning in 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, in 2022, the effects of Russian sanctions amidst the conflict with Ukraine have pushed oil and gas prices higher. However, there remains the potential for demand for oil and natural gas to be adversely impacted by the economic effects of rising interest rates and tightening monetary policies, as well as 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, the Company is unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by these or other factors. The results presented in this Form 10-Q are not necessarily indicative of future operating results. For further information regarding the actual and potential impacts of COVID-19 on the Company, see “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.
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 reduced 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, in 2022, the effects of Russian sanctions amidst the conflict with Ukraine have pushed oil and gas prices higher. However, there remains the potential for demand for oil and natural gas to be adversely impacted by the economic effects of rising interest rates and tightening monetary policies, as well as 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 these or other factors. 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
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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 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 a third party for the purchase of chemicals to treat sour gas production through December 31, 2022. The future payments associated with the minimum volume commitment are approximately $4.9 million. Our 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 March 31, 2022, we had $43.5 million of cash and cash equivalents, $200.0 million of indebtedness outstanding, approximately $1.6 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. On April 29, 2022, we borrowed the $20.0 million available under the first delayed draw of the Term Loan 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 cash on hand in excess of certain maximum levels. For each fiscal quarter after January 1, 2023, we are required to make mandatory prepayments when our 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 under our Term Loan Agreement 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 them 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 our previous revolving credit agreement for the fiscal quarter ended June 30, 2020. Thus, o n July 31, 2020, we secured a waiver in which the lenders consented to waive maintenance of the current ratio under the agreement for the fiscal quarter ended June 30, 2020. In conjunction with the fall 2020 borrowing base redetermination process under the revolving credit facility, and due to a decline in the value associated with our derivative contracts, we pursued additional relief from our
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lenders in regards to the current ratio. On October 29, 2020, in an amendment to the 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 revolving credit agreement was amended and restated by the Term Loan Agreement in November 2021.
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
During the three months ended March 31, 2022, operating cash flows 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 and cash equivalents is summarized as follows (in thousands):
Three Months Ended
March 31,
2022
2021
Cash flows provided by (used in) operating activities
$
12,047
$
13,358
Cash flows provided by (used in) investing activities
(15,844)
(12,719)
Cash flows provided by (used in) financing activities
(925)
(3,263)
Net increase (decrease) in cash, cash equivalents and restricted cash
$
(4,722)
$
(2,624)
Operating Activities. Net cash flows provided by operating activities for the three months ended March 31, 2022 and 2021 were $12.0 million and $13.4 million, respectively.
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Operating cash flows for the three months ended March 31, 2022 decreased from the three months ended March 31, 2021 due to realized losses from derivative contracts incurred in the three months ended March 31, 2022 as a result of increased commodity prices partially offset by higher total operating revenues due to an approximate $18.42 per Boe increase in average realized prices in the three months ended March 31, 2022.
Operating cash flows for the three months ended March 31, 2021 increased slightly between the first three months of 2021 and 2020. Our average realized price increase of approximately $15.34 per Boe contributed to higher total operating revenues in 2021 which were partially offset by payments on derivative settlements in 2021.
Investing Activities. Net cash flows used in investing activities for the three months ended March 31, 2022 and 2021 were approximately $15.8 million and $12.7 million, respectively.
During the three months ended March 31, 2022, we spent $15.7 million on oil and natural gas capital expenditures, of which $12.9 million related to drilling and completion costs and $1.7 million related to the development of our treating equipment and gathering support infrastructure.
During the three months ended March 31, 2021, we spent $13.8 million on oil and natural gas capital expenditures, of which $10.8 million related to drilling and completion costs and $2.2 million related to the development of our treating equipment and gathering support infrastructure. We received $1.1 million in proceeds from the sale of oil and natural gas properties.
Financing Activities. Net cash flows used in financing activities for the three months ended March 31, 2022 and 2021 were approximately $0.9 million and $3.3 million.
During the three months ended March 31, 2021, we used cash flows from operations to make net repayments of $3.0 million on our revolving credit agreement.
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 previous revolving credit agreement. 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. On April 29, 2022, we borrowed the $20.0 million available under the first delayed draw of the Term Loan Agreement. 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%.
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 cash on hand in excess of certain maximum levels. For each fiscal quarter after January 1, 2023, we are required to make mandatory prepayments when our 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
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indirect subsidiaries, and all 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 March 31, 2022, 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 1. Notes to the Unaudited Condensed Consolidated Financial Statements– Note 5, “Debt” for additional information on the Term Loan Agreement.
Paycheck Protection Program Loan
On April 16, 2020, we entered into a promissory note (the PPP Loan) for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act), which is administered by the U.S. Small Business Administration (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, if not forgiven, 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 unaudited condensed consolidated statements of operations for the year ended December 31, 2021. As of March 31, 2022, the $0.2 million principal amount of the PPP Loan was repaid in full.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2021.
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Results of Operations
Three Months Ended March 31, 2022 and 2021
We reported a net loss of $92.7 million and $33.4 million for the three months ended March 31, 2022 and 2021, respectively. The table included below sets forth financial information for the periods presented.
Three Months Ended
March 31,
In thousands (except per unit and per Boe amounts)
2022
2021
Change
Net income (loss)
$
(92,744)
$
(33,375)
$
(59,369)
Operating revenues:
Oil
62,524
41,270
21,254
Natural gas
8,881
9,087
(206)
Natural gas liquids
10,003
4,909
5,094
Other
194
252
(58)
Operating expenses:
Production:
Lease operating
11,524
9,467
2,057
Workover and other
865
560
305
Taxes other than income
4,951
3,192
1,759
Gathering and other
15,255
13,171
2,084
General and administrative:
General and administrative
4,601
4,233
368
Stock-based compensation
384
594
(210)
Depletion, depreciation and accretion:
Depletion – Full cost
10,067
10,341
(274)
Depreciation – Other
44
126
(82)
Accretion expense
109
128
(19)
Other income (expenses):
Net gain (loss) on derivative contracts
(123,858)
(45,711)
(78,147)
Interest expense and other
(2,688)
(1,370)
(1,318)
Production:
Oil – MBbls
670
719
(49)
Natural Gas - MMcf
2,315
2,133
182
Natural gas liquids – MBbls
273
215
58
Total MBoe (1)
1,329
1,290
39
Average daily production – Boe/d (1)
14,767
14,333
434
Average price per unit (2) :
Oil price - Bbl
$
93.32
$
57.40
$
35.92
Natural gas price - Mcf
3.84
4.26
(0.42)
Natural gas liquids price - Bbl
36.64
22.83
13.81
Total per Boe (1)
61.26
42.84
18.42
Average cost per Boe:
Production:
Lease operating
$
8.67
$
7.34
$
1.33
Workover and other
0.65
0.43
0.22
Taxes other than income
3.73
2.47
1.26
Gathering and other
11.48
10.21
1.27
General and administrative:
General and administrative
3.46
3.28
0.18
Stock-based compensation
0.29
0.46
(0.17)
Depletion
7.57
8.02
(0.45)
(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.
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Oil, natural gas and natural gas liquids revenues were $81.4 million and $55.3 million for the three months ended March 31, 2022 and 2021, respectively. The increase in revenues is primarily attributable to an approximate $18.42 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 three months ended March 31, 2022 and 2021, production averaged 14,767 Boe/d and 14,333 Boe/d, respectively. In February 2021, we temporarily shut-in production due to inclement weather. The estimated decrease in average daily oil and natural gas production associated with this temporary shut-in was approximately 1,300 Boe/d in the first three months of 2021. Current year production was impacted by natural production declines on our existing producing wells. We last brought new producing wells online in June 2021.
Lease operating expenses were $11.5 million and $9.5 million for the three months ended March 31, 2022 and 2021, respectively. On a per unit basis, lease operating expenses were $8.67 per Boe and $7.34 per Boe for the three months ended March 31, 2022 and 2021, respectively. The increase in lease operating expenses in 2022 results from a market increase in maintenance, power, and chemical costs.
Workover and other expenses were $0.9 million and $0.6 million for the three months ended March 31, 2022 and 2021, respectively. On a per unit basis, workover and other expenses were $0.65 per Boe and $0.43 per Boe for the three months ended March 31, 2022 and 2021, respectively. The increased workover and other expenses in 2022 relate to more significant workover projects undertaken in the current year.
Taxes other than income were $5.0 million and $3.2 million for the three months ended March 31, 2022 and 2021, 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 $3.73 per Boe and $2.47 per Boe for the three months ended March 31, 2022 and 2021, respectively.
Gathering and other expenses were $15.3 million and $13.2 million for the three months ended March 31, 2022 and 2021, 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 $6.6 million and $4.0 million for the three months ended March 31, 2022 and 2021, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Gathering and marketing fees increased in 2022 as we marketed higher quantities of sour gas production to third parties in the current year period. Approximately $8.7 million and $9.2 million for the three months ended March 31, 2022 and 2021, respectively, relate to operating expenses on our treating equipment and gathering support facilities. The decrease in treating equipment and gathering support facilities expenses in 2022 results from lower operating expenses associated with our treating equipment .
General and administrative expense was $4.6 million and $4.2 million for the three months ended March 31, 2022 and 2021, respectively. The increase in general and administrative expense in the current year period is associated with an increase in salaries and benefits costs as well as professional fees incurred, which were partially offset by a decrease in corporate office lease expense. On a per unit basis, general and administrative expenses were $3.46 per Boe and $3.28 per Boe for the three months ended March 31, 2022 and 2021, respectively.
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 $10.1 million and $10.3 million for the three months ended March 31, 2022 and 2021, respectively. On a per unit basis, depletion expense was $7.57 per Boe and $8.02 per Boe for the three months ended March 31, 2022 and 2021, respectively. The depletable base of our unit of production calculation in 2022 was increased by future development costs associated with PUD reserve additions since the three months ended March 31, 2021. We also experienced an increase in proved reserve volumes, primarily from PUD reserve additions, which resulted in a decrease to our depletion rate in 2022 as compared to 2021.
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We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids 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 unaudited condensed consolidated statements of operations. At March 31, 2022, we had a $8.8 million derivative asset, $3.6 million of which was classified as current, and we had a $161.4 million derivative liability, $103.2 million of which was classified as current. We recorded a net derivative loss of $123.9 million ($91.1 million net unrealized loss and $32.8 million net realized loss on settled contracts) for the three months ended March 31, 2022. For the three months ended March 31, 2021, we recorded a net derivative loss of $45.7 million ($36.0 million net unrealized loss and $9.7 million net realized loss on settled and early terminated contracts).
Interest expense and other was $2.7 million and $1.4 million for the three months ended March 31, 2022 and 2021, respectively. Interest expense and other increased in the current period due to higher interest and the amortization of debt issuance costs associated with our Term Loan Agreement and was partially offset by a $2.0 million change in fair value of the Change of Control Call Option.
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Recently Issued Accounting Pronouncements
We discuss recently adopted and issued accounting standards in Item 1. Condensed Consolidated Financial Statements (Unaudited) —Note 1, “ Financial Statement Presentation .”
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