The following discussion is intended to assist in understanding our results of
operations for the three and nine months ended September 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 nine months of 2022 and 2021 were
$282.3 million and $200.7 million, respectively. The increase in revenues is
primarily attributable to an approximate $21.07 per Boe increase in average
realized prices (excluding the effects of hedging arrangements). During the
first nine months of 2022, production averaged 15,352 Boe/d. For the nine months
ended September 30, 2022, we drilled and cased 8 gross (7.5 net) operated wells
and completed and put online 5 gross (4.5 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 period ending at the balance
sheet date. Using the crude oil price for October 2022 of $79.79 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
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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. We currently expect the AGI facility will
be in service in the first quarter of 2023. Once in service, the GTA has a
tiered-rate structure which is expected to drive a greater than 50 percent
reduction in treating fees. Our current estimates of facility in-service dates
and future treating fee reductions are subject to various operational and other
risk factors, some of which our beyond our control, which could impact the
timing and extent of these estimates.
Capital Resources and Liquidity
Overview. At September 30, 2022, we had $33.5 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 $2.8 million
associated with an active drilling rig commitment through the fourth quarter of
2022. We also have a minimum volume commitment of approximately $1.6 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 entered into in
2019. As of September 30, 2022, the Company had borrowed $220.0 million under
the Term Loan Agreement, a portion of which was used to refinance all amounts
owed under the Senior Credit Agreement, and had approximately $1.3 million
letters of credit outstanding. Under the Term Loan Agreement, the lenders have
also agreed to loan the Company up to an additional $15.0 million, which 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%.
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On November 14, 2022, the Company paid approximately $2.4 million and entered
into a further Amended Credit Agreement (the "Amended Term Loan Agreement") with
its lenders which modified certain provisions of its original Term Loan
Agreement including, but not limited to, the following:
Current Ratio. Our Current Ratio financial covenant decreased to 0.9 to 1.00 as
of September 30, 2022, to 0.70 to 1.00 for the quarter ended December 31, 2022,
? and to 0.75 to 1.00 for the quarter ended March 31, 2023, returning to 1.00 to
1.00 for the quarter ended June 30, 2023 and each quarter thereafter as further
described below.
Interest Rate. Effective on the amendment date, we (i) converted the benchmark
interest rate to the Secured Overnight Financing Rate (SOFR) and (ii) increased
? the applicable margin on borrowings by 0.50%, such that borrowings under the
Term Loan Agreement will now bear interest at a rate per annum equal to the
SOFR plus an applicable margin of 7.50%.
We reset the prepayment periods (for outstanding borrowings) beginning on the
? amendment date with the following prepayment premiums, subject to the
conditions in the table below and the discussion that follows:
Period (after
amendment date) Premium
Months 0 - 12 Make-whole amount equal to 12 months of interest plus 2.00%
Months 13 - 24 2.00%
Thereafter 0.00%
If within 6 months after the November 14, 2022 amendment date the Company raises
a minimum of $20 million of new capital in the form of equity, equity-linked,
preferred equity, or unsecured debt, in call cases bearing no cash dividend or
cash interest, to bolster liquidity or repay debt, our prepayment premiums will
reset to those in the original credit agreement (as further described in our
2021 Annual Report on Form 10-K). Additionally, if a change of control results
in prepayment within the second anniversary of the amendment date, a 2% payment
premium will apply.
We may be required to make mandatory prepayments of the loans under the Amended
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 our Consolidated Cash Balance, as
defined in the Amended 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 Amended 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 Amended Term Loan Agreement there are certain restrictions on the
transfer of assets, including cash, to Battalion from the guarantor
subsidiaries.
The Amended Term Loan Agreement also contains certain financial covenants (as
defined), including the maintenance of the following ratios:
? Asset Coverage Ratio of not less than 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 3.00 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, other than as amended in November 2022 to 0.9 to
1 as of September 30, 2022, to 0.70 to 1 for the quarter ended December 31,
2022, and to 0.75 to 1 for the quarter ended March 31, 2023.
As of September 30, 2022, (i) the Company was in compliance with the Asset
Coverage Ratio and Total Net Leverage Ratio covenants under the Term Loan
Agreement and (ii) our Current Ratio was 0.96 to 1, which was less than
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the 1.00 to 1.00 Current Ratio required under the original terms of the Term
Loan Agreement. As a result of the amendment to our Term Loan Agreement in
November 2022, we were in compliance with the amended Current Ratio covenant of
0.9 to 1 for the quarter ended September 30, 2022.
The Amended Term Loan Agreement also contains an APOD for our Monument Draw
acreage through the drilling and completion of certain wells. The Amended 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 Amended 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 Amended Term Loan Agreement. As a consequence, we endeavor
to anticipate potential covenant compliance issues and work with our lenders
under our Amended 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, as evidenced most recently by the amendment of our Term
Loan Agreement in November 2022 which reduced the Current Ratio covenant as of
September 30, 2022 and each successive quarter through the quarter ended March
31, 2023, there can be no assurance that we will be successful in the future. In
the event we are not successful in obtaining future modifications or amendments
to our covenants, 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 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,
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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):
Nine Months Ended
September 30,
2022 2021
Cash flows provided by (used in) operating activities $ 53,814 $ 47,132
Cash flows provided by (used in) investing activities
(87,780) (46,248)
Cash flows provided by (used in) financing activities 19,166 (3,311)
Net increase (decrease) in cash, cash equivalents and $ $
restricted cash (14,800) (2,427)
Operating Activities. Net cash flows provided by operating activities for the
nine months ended September 30, 2022 and 2021 were $53.8 million and $47.1
million, respectively. Items impacting operating cash flows were (i) higher
total operating revenues resulting from an approximate $21.07 per Boe increase
in average realized prices (excluding the impact of hedging arrangements) for
the nine months ended September 30, 2022 compared to the nine months ended
September 30, 2021 partially offset by realized losses from derivative
contracts, (ii) increased operating and interest costs in 2022, and (iii)
changes in working capital.
Investing Activities. Net cash flows used in investing activities for the nine
months ended September 30, 2022 and 2021 were approximately $87.8 million and
$46.2 million, respectively.
During the nine months ended September 30, 2022, we spent $87.0 million on oil
and natural gas capital expenditures, of which $77.5 million related to drilling
and completion costs and $6.8 million related to the development of our treating
equipment and gathering support infrastructure.
During the nine months ended September 30, 2021, we spent $47.2 million on oil
and natural gas capital expenditures, of which $39.4 million related to drilling
and completion costs and $5.7 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 (used in) financing activities
for the nine months ended September 30, 2022 and 2021 were $19.2 million and
$(3.3) million, respectively. During the nine months ended September 30, 2022,
we borrowed the $20 million available under the first delayed draw of the Term
Loan Agreement. During the nine months ended September 30, 2021, net borrowings
of $3.0 million under our Senior Credit Agreement were funded with cash flows
from operations.
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
We reported a net income of $105.9 million and $13.1 million for the three
months ended September 30, 2022 and 2021, and a net income (loss) of $26.2
million and $(54.3) million for the nine months ended September 30, 2022 and
2021, respectively. The table included below sets forth financial information
for the periods presented.
Three Months Ended Nine Months Ended
September 30, September 30,
In thousands (except per unit and
per Boe amounts) 2022 2021 2022 2021
Net income (loss) $ 105,888 $ 13,052 $ 26,191 $ (54,252)
Operating revenues:
Oil 70,406 60,023 206,874 153,228
Natural gas 15,656 9,435 39,296 23,839
Natural gas liquids 12,644 11,046 35,234 22,806
Other 443 312 858 827
Operating expenses:
Production:
Lease operating 12,265 11,979 35,698 31,615
Workover and other 2,559 990 4,807 2,317
Taxes other than income 5,613 3,082 15,936 9,186
Gathering and other 16,663 15,934 47,787 43,436
General and administrative:
General and administrative 3,815 4,010 12,531 11,789
Stock-based compensation 683 481 1,540 1,560
Depletion, depreciation and
accretion:
Depletion - Full cost 13,391 10,714 35,872 32,070
Depreciation - Other 110 61 230 292
Accretion expense 114 110 334 367
Other income (expenses):
Net gain (loss) on derivative
contracts 67,634 (20,571) (88,134) (119,371)
Interest expense and other (5,682) (1,900) (13,202) (5,017)
Gain (loss) on extinguishment of
debt - 2,068 - 2,068
Production:
Oil - MBbls 753 872 2,097 2,396
Natural Gas - MMcf 2,352 2,589 7,022 6,777
Natural gas liquids - MBbls 348 327 924 812
Total MBoe(1) 1,493 1,631 4,191 4,338
Average daily production - Boe(1) 16,228 17,728 15,352 15,890
Average price per unit (2):
Oil price - Bbl $ 93.50 $ 68.83 $ 98.65 $ 63.95
Natural gas price - Mcf 6.66 3.64 5.60 3.52
Natural gas liquids price - Bbl 36.33 33.78 38.13 28.09
Total per Boe(1) 66.11 49.36 67.14 46.07
Average cost per Boe:
Production:
Lease operating $ 8.22 $ 7.34 $ 8.52 $ 7.29
Workover and other 1.71 0.61 1.15 0.53
Taxes other than income 3.76 1.89 3.80 2.12
Gathering and other 11.16 9.77 11.40 10.01
General and administrative:
General and administrative 2.56 2.46 2.99 2.72
Stock-based compensation 0.46 0.29 0.37 0.36
Depletion 8.97 6.57 8.56 7.39
(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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Operating Revenues. Oil, natural gas and natural gas liquids revenues were $98.7
million and $80.5 million for the three months ended September 30, 2022 and 2021
and $281.4 million and $199.9 million for the nine months ended September 30
2022 and 2021, respectively. The increase in revenues is primarily attributable
to an increase in our average realized prices partially offset by slightly lower
production volumes in 2022 compared to 2021. Average realized prices (excluding
the effects of hedging arrangements) increased approximately $16.75 per Boe and
$21.07 per Boe increase, respectively, for the quarter and nine months ended
September 30, 2022 when compared with the same periods in 2021. 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.
Production for the three months ended September 30, 2022 and 2021, averaged
16,228 Boe/d and 17,728 Boe/d and 15,352 Boe/d and 15,890 Boe/d for the nine
months ended September 30, 2022 and 2021, respectively. While production is
lower in 2022 compared with 2021 due largely to the timing of capital
expenditures and natural production declines on our existing producing wells,
our production has increased from 14,767 Boe/d in the first quarter of 2022 to
16,228 Boe/d in the third quarter of 2022 and we have put online 5 gross (4.5
net) operated wells in 2022. Also impacting 2021 production volumes was
temporarily shut-in production due to inclement weather which decreased average
daily production by approximately 400 Boe/d in the first nine months of 2021.
Lease Operating Expenses. Lease operating expenses were $12.3 million and $12.0
million for the three months ended September 30, 2022 and 2021 and $35.7 million
and $31.6 million for the nine months ended September 30, 2022 and 2021,
respectively. On a per unit basis, lease operating expenses were $8.22 per Boe
and $7.34 per Boe for the three months ended September 30, 2022 and 2021 and
$8.52 per Boe and $7.29 per Boe for the nine months ended September 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. Workover and other expenses were $2.6 million and
$1.0 million for the three months ended September 30, 2022 and 2021 and $4.8
million and $2.3 million for the nine months ended September 30, 2022 and 2021,
respectively. On a per unit basis, workover and other expenses were $1.71 per
Boe and $0.61 per Boe for the three months ended September 30, 2022 and 2021 and
$1.15 per Boe and $0.53 per Boe for the nine months ended September 30, 2022 and
2021, respectively. The increased workover and other expenses in 2022 relate to
more significant workover projects undertaken in the current periods as well as
market increases in service and material costs in 2022.
Taxes Other than Income. Taxes other than income were $5.6 million and $3.1
million for the three months ended September 30, 2022 and 2021 and $15.9 million
and $9.2 million for the nine months ended September 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 $3.76 per Boe and $1.89 per Boe for the
three months ended September 30, 2022 and 2021 and $3.80 per Boe and $2.12 per
Boe for the nine months ended September 30, 2022 and 2021, respectively.
Gathering and Other Expenses. Gathering and other expenses were $16.7 million
and $15.9 million for the three months ended September 30, 2022 and 2021 and
$47.8 million and $43.4 million for the nine months ended September 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 $7.0 million and $6.3
million for the three months ended September 30, 2022 and 2021 and $20.5 million
and $15.0 million for the nine months ended September 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 $9.7 million and $9.6 million for the
three months ended September 30, 2022 and 2021 and $27.5 million and $28.5
million for the nine months ended September 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 for the year-to-date period results from lower operating expenses
associated with our treating equipment.
General and Administrative Expense. General and administrative expense was $3.8
million and $4.0 million for the three months ended September 30, 2022 and 2021
and $12.5 million and $11.8 million for the nine months ended
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September 30, 2022 and 2021, respectively. The decrease in general and
administrative expense for the quarter ended September 30, 2022 compared with
2021 is primarily associated with a decrease in office rent and payroll and
benefits partially offset by an increase in professional fees. The increase in
general and administrative expense for the year-to-date period in 2022 is
primarily associated with an increase in professional fees and payroll and
benefits partially offset by a decrease in corporate office lease expense. On a
per unit basis, general and administrative expenses were $2.56 per Boe and $2.46
per Boe for the three months ended September 30, 2022 and 2021 and $2.99 per Boe
and $2.72 per Boe for the nine months ended September 30, 2022 and 2021,
respectively.
Depletion, Depreciation, and Amortization Expense. 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
$13.4 million and $10.7 million for the three months ended September 30, 2022
and 2021 and $35.9 million and $32.1 million for the nine months ended September
30, 2022 and 2021, respectively. On a per unit basis, depletion expense was
$8.97 per Boe and $6.57 per Boe for the three months ended September 30, 2022
and 2021 and $8.56 per Boe and $7.39 per Boe for the nine months ended September
30, 2022 and 2021, respectively. The increase in our depletion rate for the
quarter and nine month periods ended September 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 periods.
Net gain (loss) on derivative contracts. 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 September 30, 2022, we had a $27.0 million
derivative asset ($18.2 million current) and a $64.7 million derivative
liability ($41.1 million current). For the three months ended September 30,
2022, we recorded a net derivative gain of $67.6 million ($102.1 million net
unrealized gain and $34.5 million net realized loss on settled contracts). For
the nine months ended September 30, 2022, we recorded a net derivative loss of
$88.1 million ($23.9 million net unrealized gain and $112.0 million net realized
loss on settled contract). For the three months ended September 30, 2021, we
recorded a net derivative loss of $20.6 million ($1.8 million net unrealized
gain and $22.4 million net realized loss on settled and early terminated
contracts). For the nine months ended September 30, 2021, we recorded a net
derivative loss of $119.4 million ($69.1 million net unrealized loss and $50.3
million net realized loss on settled and early terminated contracts).
Interest Expense and Other. Interest expense and other was $5.7 million and $1.9
million for the three months ended September 30, 2022 and 2021 and $13.2 and
$5.0 for the nine months ended September 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 $0.4 million and $3.0 million change,
respectively in the fair value of the Change of Control Call Option (as further
discussed in Note 5, "Debt") for the quarter and nine months ended September 30,
2022.
Gain (loss) on extinguishment of debt. During the quarter and nine months ended
September 30, 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. During the first quarter of 2022, the
$0.2 million principal amount of the PPP loan was repaid in full.
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