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 and six months ended June 30, 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. The results presented in this Form 10-Q are not necessarily indicative of future operating results.
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 six months of 2022 and 2021 were $183.1 million and $119.9 million, respectively. The increase in revenues is primarily attributable to an approximate $23.62 per Boe increase in average realized prices (excluding the effects of hedging arrangements). During the first six months of 2022, production averaged 14,906 Boe/d compared to average production of 14,956 Boe/d during the six 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 600 Boe/d in the first six months of 2021. Current year production was impacted by natural production declines on our existing producing wells. For the six months ended June 30, 2022, we drilled and cased 5 gross (4.84 net) operated wells and completed and put online 5 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.
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.
Additionally, since oil and natural gas prices are inherently volatile, 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
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period ending at the balance sheet date. Using the crude oil price for July 2022 of $110.2 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.
Recent Developments
In May 2022, we entered into a joint venture agreement with Caracara Services, LLC (“Caracara”) to develop a strategic acid gas treatment and carbon sequestration facility (the “Facility”) in Winkler County, Texas. The joint venture, operating as Brazos Amine Treater, LLC (“BAT”), has also entered into a Gas Treating Agreement (“GTA”) with us for gas production from our Monument Draw area. In exchange for contributing to the joint venture a wellbore with an approved permit for the injection of acid gas and surface land , we retained a 5% equity interest in BAT, an unconsolidated subsidiary. Caracara is obligated to provide all necessary capital for the construction of the Facility, which is expected to come online on or before twelve months from the effective date of the GTA, with an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H2S and CO2. Under the GTA, we will pay a treating rate that varies based on volumes delivered to the Facility for a term that will last 20 years from the in-service date of the Facility and have a minimum volume commitment of 20 MMcf per day, with certain rollover rights and start-up flexibility, for an initial term of five years from the in service date of the Facility, which can be extended up to seven years under certain conditions.
Capital Resources and Liquidity
Overview. At June 30, 2022, we had $43.6 million of cash and cash equivalents, $220.0 million of indebtedness outstanding, approximately $1.3 million letters of credit outstanding and $15.0 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.
Capital Expenditures. During 2022, we expect to spend approximately $130.0 million to $150.0 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs. Included in our remaining 2022 capital expenditures budget is approximately $4.7 million associated with an active drilling rig commitment through the fourth quarter of 2022. We also have a minimum volume commitment of approximately $3.3 million with a third party for the purchase of chemicals to treat sour gas production through December 31, 2022. 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 (which is further described below) and cash flows from operations.
Debt Obligations. 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 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 under the first delayed draw of the Term Loan Agreement, which was drawn on April 29, 2022 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%.
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, or with cash on hand in excess of certain maximum levels beginning in 2023. For each fiscal quarter after January 1, 2023, we are required to make mandatory prepayments when
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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 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 (as defined in the Term Loan Agreement), including the maintenance of the following ratios:
● Asset Coverage Ratio of not less than 1.60 to 1.00 as of June 30, 2022, 1.70 to 1.00 as of September 30, 2022, and 1.80 to 1.00 as of December 31, 2022 and each fiscal quarter thereafter
● Total Net Leverage Ratio of not greater than 3.25 to 1.00 as of June 30, 2022, 3.00 to 1.00 as of September 30, 2022 and December 31, 2022, 2.75 to 1.00 as of March 31, 2023, and 2.50 to 1.00 as of each fiscal quarter thereafter, and
● Current Ratio of not less than 1.00 to 1.00, each determined as of the last day of any fiscal quarter period.
As of June 30, 2022, the Company was 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.
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.
While we have been largely been successful in obtaining modifications of our covenants as needed (which last occurred in 2020 under our revolving credit facility which was replaced by our Term Loan Agreement in 2021), 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.
Other Risks and Uncertainties. 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
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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 .
In periods of increasing commodity prices, the Company also continues to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business . During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater. The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.
We are also 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.
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. For further information regarding risk factors which could impact 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.
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 international conflicts, 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.
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Cash Flow
Net increase (decrease) in cash and cash equivalents is summarized as follows (in thousands):
Six Months Ended
June 30,
2022
2021
Cash flows provided by (used in) operating activities
$
28,333
$
29,100
Cash flows provided by (used in) investing activities
(51,986)
(36,669)
Cash flows provided by (used in) financing activities
19,069
4,732
Net increase (decrease) in cash, cash equivalents and restricted cash
$
(4,584)
$
(2,837)
Operating Activities . Net cash flows provided by operating activities for the six months ended June 30, 2022 and 2021 were $28.3 million and $29.1 million, respectively. Operating cash flows for the six months ended June 30, 2022 decreased from the six months ended June 30, 2021 due primarily to realized losses from derivative contracts incurred in the six months ended June 30, 2022 as a result of increased commodity prices partially offset by higher total operating revenues due to an approximate $23.62 per Boe increase in average realized prices in the six months ended June 30, 2022.
Investing Activities. Net cash flows used in investing activities for the six months ended June 30, 2022 and 2021 were approximately $52.0 million and $36.7 million, respectively.
During the six months ended June 30, 2022, we spent $51.4 million on oil and natural gas capital expenditures, of which $45.7 million related to drilling and completion costs and $3.8 million related to the development of our treating equipment and gathering support infrastructure.
During the six months ended June 30, 2021, we spent $37.6 million on oil and natural gas capital expenditures, of which $33.0 million related to drilling and completion costs and $3.1 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.
Financing Activities. Net cash flows provided by financing activities for the six months ended June 30, 2022 and 2021 were approximately $19.1 million and $4.7 million. During the six months ended June 30, 2022, we borrowed the $20 million available under the first delayed draw of the Term Loan Agreement. During the six months ended June 30, 2021, net borrowings of $5.0 million under our Senior Credit Agreement were used to partially fund our drilling and completions program and the development of our treating equipment and gathering support facilities.
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 June 30, 2022 and 2021
We reported a net income (loss) of $13.0 million and $(33.9) million for the three months ended June 30, 2022 and 2021, respectively. The table included below sets forth financial information for the periods presented.
Three Months Ended
June 30,
In thousands (except per unit and per Boe amounts)
2022
2021
Change
Net income (loss)
$
13,047
$
(33,929)
$
46,976
Operating revenues:
Oil
73,944
51,935
22,009
Natural gas
14,759
5,317
9,442
Natural gas liquids
12,587
6,851
5,736
Other
221
263
(42)
Operating expenses:
Production:
Lease operating
11,909
10,169
1,740
Workover and other
1,383
767
616
Taxes other than income
5,372
2,912
2,460
Gathering and other
15,869
14,331
1,538
General and administrative:
General and administrative
4,115
3,546
569
Stock-based compensation
473
485
(12)
Depletion, depreciation and accretion:
Depletion – Full cost
12,414
11,015
1,399
Depreciation – Other
76
105
(29)
Accretion expense
111
129
(18)
Other income (expenses):
Net gain (loss) on derivative contracts
(31,910)
(53,089)
21,179
Interest expense and other
(4,832)
(1,747)
(3,085)
Production:
Oil – MBbls
674
805
(131)
Natural Gas - MMcf
2,355
2,055
300
Natural gas liquids – MBbls
303
270
33
Total MBoe (1)
1,369
1,417
(48)
Average daily production – Boe/d (1)
15,044
15,571
(527)
Average price per unit (2) :
Oil price - Bbl
$
109.71
$
64.52
$
45.19
Natural gas price - Mcf
6.27
2.59
3.68
Natural gas liquids price - Bbl
41.54
25.37
16.17
Total per Boe (1)
73.99
45.24
28.75
Average cost per Boe:
Production:
Lease operating
$
8.70
$
7.18
$
1.52
Workover and other
1.01
0.54
0.47
Taxes other than income
3.92
2.06
1.86
Gathering and other
11.59
10.11
1.48
General and administrative:
General and administrative
3.01
2.50
0.51
Stock-based compensation
0.35
0.34
0.01
Depletion
9.07
7.77
1.30
(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 $101.3 million and $64.1 million for the three months ended June 30, 2022 and 2021, respectively . The increase in revenues is primarily attributable to an approximate $28.75 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 June 30, 2022 and 2021, production averaged 15,044 Boe/d and 15,571 Boe/d, respectively.
Lease operating expenses were $11.9 million and $10.2 million for the three months ended June 30, 2022 and 2021, respectively. On a per unit basis, lease operating expenses were $8.70 per Boe and $7.18 per Boe for the three months ended June 30, 2022 and 2021, respectively. The increase in lease operating expenses in 2022 results primarily from a market increase in maintenance, power, and chemical costs..
Workover and other expenses were $1.4 million and $0.8 million for the three months ended June 30, 2022 and 2021, respectively. On a per unit basis, workover and other expenses were $1.01 per Boe and $0.54 per Boe for the three months ended June 30, 2022 and 2021, respectively. The increased workover and other expenses in 2022 relate to more significant workover projects undertaken in the current period.
Taxes other than income were $5.4 million and $2.9 million for the three months ended June 30, 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 $3.92 per Boe and $2.06 per Boe for the three months ended June 30, 2022 and 2021, respectively.
Gathering and other expenses were $15.9 million and $14.3 million for the three months ended June 30, 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 $6.8 million and $4.6 million for the three months ended June 30, 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 $9.1 million and $9.7 million for the three months ended June 30, 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 $4.1 million and $3.5 million for the three months ended June 30, 2022 and 2021, respectively. The increase in general and administrative expense in the current period is primarily associated with an increase in professional fees partially offset by a decrease in corporate office lease expense, payroll and benefits costs. On a per unit basis, general and administrative expenses were $3.01 per Boe and $2.50 per Boe for the three months ended June 30, 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 $12.4 million and $11.0 million for the three months ended June 30, 2022 and 2021, respectively. On a per unit basis, depletion expense was $9.07 per Boe and $7.77 per Boe for the three months ended June 30, 2022 and 2021, respectively. The increase in our depletion rate for the quarter ended June 30, 2022 compared to the same period in 2021 is primarily due to increased future development costs in 2022 compared to 2021 associated with PUD reserve additions during the period s
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 June 30, 2022, we had a $10.1 million derivative asset, $6.1 million of which was classified as current, and we had a $149.9 million derivative liability, $91.8 million of which was classified as current. We recorded a net derivative loss of $31.9
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million ($12.8 million net unrealized gain and $44.7 million net realized loss on settled contracts) for the three months ended June 30, 2022. For the three months ended June 30, 2021, we recorded a net derivative loss of $53.1 million ($34.8 million net unrealized loss and $18.3 million net realized loss on settled and early terminated contracts).
Interest expense and other was $4.8 million and $1.7 million for the three months ended June 30, 2022 and 2021, respectively. Interest expense and other primarily increased in the current period due to higher debt balances in 2022, increased interest rates and amortization of debt issuance costs associated with our Term Loan Agreement entered into in 2022. This was partially offset by a $0.6 million change in the fair value of the Change of Control Call Option.
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Six Months Ended June 30, 2022 and 2021
We reported a net loss of $(79.7) million and $(67.3) million for the six months ended June 30, 2022 and 2021, respectively. The table included below sets forth financial information for the periods presented.
Six Months Ended
June 30,
In thousands (except per unit and per Boe amounts)
2022
2021
Change
Net income (loss)
$
(79,697)
$
(67,304)
$
(12,393)
Operating revenues:
Oil
136,468
93,205
43,263
Natural gas
23,640
14,404
9,236
Natural gas liquids
22,590
11,760
10,830
Other
415
515
(100)
Operating expenses:
Production:
Lease operating
23,433
19,636
3,797
Workover and other
2,248
1,327
921
Taxes other than income
10,323
6,104
4,219
Gathering and other
31,124
27,502
3,622
General and administrative:
General and administrative
8,716
7,779
937
Stock-based compensation
857
1,079
(222)
Depletion, depreciation and accretion:
Depletion – Full cost
22,481
21,356
1,125
Depreciation – Other
120
231
(111)
Accretion expense
220
257
(37)
Other income (expenses):
Net gain (loss) on derivative contracts
(155,768)
(98,800)
(56,968)
Interest expense and other
(7,520)
(3,117)
(4,403)
Production:
Oil – MBbls
1,344
1,524
(180)
Natural Gas - MMcf
4,670
4,188
482
Natural gas liquids – MBbls
576
485
91
Total MBoe (1)
2,698
2,707
(9)
Average daily production – Boe (1)
14,906
14,956
(50)
Average price per unit (2) :
Oil price - Bbl
$
101.54
$
61.16
$
40.38
Natural gas price - Mcf
5.06
3.44
1.62
Natural gas liquids price - Bbl
39.22
24.25
14.97
Total per Boe (1)
67.72
44.10
23.62
Average cost per Boe:
Production:
Lease operating
$
8.69
$
7.25
$
1.44
Workover and other
0.83
0.49
0.34
Taxes other than income
3.83
2.25
1.58
Gathering and other
11.54
10.16
1.38
General and administrative:
General and administrative
3.23
2.87
0.36
Stock-based compensation
0.32
0.40
(0.08)
Depletion
8.33
7.89
0.44
(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio is based on energy equivalency, not price equivalency. The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil.
(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 $182.7 million and $119.4 million for the six months ended June 30, 2022 and 2021, respectively. The increase in revenues is primarily attributable to an approximate $23.62 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 six months ended June 30, 2022 and 2021, production averaged 14,906 Boe/d and 14,956 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 600 Boe/d in the first six months of 2021. Current year production was impacted by natural production declines on our existing producing wells.
Lease operating expenses were $23.4 million and $19.6 million for the six months ended June 30, 2022 and 2021, respectively. On a per unit basis, lease operating expenses were $8.69 per Boe and $7.25 per Boe for the six months ended June 30, 2022 and 2021, respectively. The increase in lease operating expenses in 2022 results primarily from a market increase in maintenance, power, and chemical costs.
Workover and other expenses were $2.2 million and $1.3 million for the six months ended June 30, 2022 and 2021, respectively. On a per unit basis, workover and other expenses were $0.83 per Boe and $0.49 per Boe for the six months ended June 30, 2022 and 2021, respectively. The increased workover and other expenses in 2022 relate to more significant workover projects undertaken in the current period.
Taxes other than income were $10.3 million and $6.1 million for the six months ended June 30, 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 $3.83 per Boe and $2.25 per Boe for the six months ended June 30, 2022 and 2021, respectively.
Gathering and other expenses were $31.1 million and $27.5 million for the six months ended June 30, 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 $13.4 million and $8.6 million for the six months ended June 30, 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 $17.8 million and $18.9 million for the six months ended June 30, 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 $8.7 million and $7.8 million for the six months ended June 30, 2022 and 2021, respectively. The increase in general and administrative expense in the current year period is primarily associated with an increase in professional fees and payroll and benefits. On a per unit basis, general and administrative expenses were $3.23 per Boe and $2.87 per Boe for the three months ended June 30, 2022 and 2021, respectively.
Depletion expense was $22.5 million and $21.4 million for the six months ended June 30, 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. On a per unit basis, depletion expense was $8.33 per Boe and $7.89 per Boe for the six months ended June 30, 2022 and 2021, respectively. The increase in our depletion rate for the six months ended June 30, 2022 compared to the same period in 2021 is primarily due to increased future development costs in 2022 compared to 2021 associated with PUD reserve additions during the period s
We enter into derivative commodity instruments to economically 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 June 30, 2022, we had a $10.1 million derivative asset, $6.1 million of which was classified as current, and we had a
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$149.9 million derivative liability, $91.8 million of which was classified as current. We recorded a net derivative loss of $155.8 million ($78.2 million net unrealized loss and $77.6 million net realized loss on settled and early terminated contracts) for the six months ended June 30, 2022. For the six months ended June 30, 2021, we recorded a net derivative loss of $98.8 million ($70.9 million net unrealized loss and $27.9 million net realized loss on settled and early terminated contracts).
Interest expense and other was $7.5 million and $3.1 million for the six months ended June 30, 2022 and 2021, respectively. Interest expense and other increased in the current period due primarily to higher debt balances in 2022, an increase in interest rates and amortization of debt issuance costs associated with our Term Loan Agreement entered in to in 2022. This was partially offset by a $2.6 million change in the fair value of the Change of Control Call Option.
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.