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Item 2. Management’s Discussion and Analysis

2022-11-14 compared with 2022-08-08 · 110 added, 156 removed, 126 unchanged (68% of the section changed)

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 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.

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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.

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 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.

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.

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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 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.

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

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

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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

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.

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.

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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.

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.

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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

our Consolidated Cash Balance, as defined in the Term Loan Agreement, exceeds $20.0 million.

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)

Months 0 - 12

Make-whole amount equal to 12 months of interest plus 2.00%

Months 13 - 24

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 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;

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

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;

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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.

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.

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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 .

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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.

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.

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Net increase (decrease) in cash and cash equivalents is summarized as follows (in thousands):

Six Months Ended

Nine Months Ended

September 30,

Cash flows provided by (used in) operating activities

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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.

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 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.

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 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.

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

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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.

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,

In thousands (except per unit and per Boe amounts)

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Interest expense and other

Gain (loss) on extinguishment of debt

Natural Gas - MMcf

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Total MBoe (1)

Average daily production – Boe/d (1)

Average daily production – Boe (1)

Average price per unit (2) :

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(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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).

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.

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.

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 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.

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 $3.92 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.

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 $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.

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 $9.1 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.

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

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 $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

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 period s.

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 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

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.

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

In thousands (except per unit and per Boe amounts)

Net income (loss)

Operating revenues:

Natural gas liquids

Operating expenses:

Lease operating

Workover and other

Taxes other than income

Gathering and other

General and administrative:

General and administrative

Stock-based compensation

Depletion, depreciation and accretion:

Depletion – Full cost

Depreciation – Other

Accretion expense

Other income (expenses):

Net gain (loss) on derivative contracts

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.

Natural Gas - MMcf

Natural gas liquids – MBbls

Total MBoe (1)

Average daily production – Boe (1)

Average price per unit (2) :

Oil price - Bbl

Natural gas price - Mcf

Natural gas liquids price - Bbl

Total per Boe (1)

Average cost per Boe:

Lease operating

Workover and other

Taxes other than income

Gathering and other

General and administrative:

General and administrative

Stock-based compensation

(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.

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).

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.

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.

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 $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.

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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis