What changed in this filing

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Item 2. Management’s Discussion and Analysis

2021-08-09 compared with 2021-05-14 · 199 added, 83 removed, 179 unchanged (61% 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 months ended March 31, 2021 and 2020 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, 2020.

The following discussion is intended to assist in understanding our results of operations for the three and six months ended June 30, 2021 and 2020 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, 2020.

Statements in this discussion may be forward-looking.

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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 three months of 2021 and 2020 were $55.5 million and $47.4 million, respectively.

The increase in revenues in the most recent period is primarily attributable to an approximate $15.34 per Boe increase in average realized prices in the most recent period.

During the first three months of 2021, production averaged 14,333 Boe/d compared to average production of 18,791 Boe/d during the first three months of 2020.

Our average daily oil and natural gas production decreased in the first three months of 2021 when compared to the same period in the prior year primarily due to production declines in our non-core areas, which were partially offset by increased production from our Monument Draw area, where new production came online as a result of our capital spending program.

Also contributing to decreased total production in the current year period is a temporary shut-in of production in February 2021 as a result of inclement weather.

The estimated production decrease associated with this temporary shut-in was approximately 1,300 Boe/d for the first three months of 2021.

In addition, in December 2020, we divested properties that produced approximately 800 Boe/d during the three months ended March 31, 2020.

For the three months ended March 31, 2021, we drilled and cased 2.0 gross (2.0 net) operated wells, completed 4.0 gross (4.0 net) operated wells, and put online 4.0 gross (4.0 net) operated wells.

Our total operating revenues for the first six months of 2021 and 2020 were $119.9 million and $65.9 million, respectively.

The increase in revenues in the most recent period is primarily attributable to an approximate $22.47 per Boe increase in average realized prices (excluding the effects of hedging arrangements).

During the first six months of 2021, production averaged 14,956 Boe/d compared to average production of 16,527 Boe/d during the first six months of 2020.

Average daily oil and natural gas production was impacted by the temporary shut-in of production amounting to approximately 600 Boe/d and 2,700 Boe/d in the first six months of 2021 and 2020, respectively.

In February 2021, we temporarily shut-in production due to inclement weather.

In May and June 2020, we temporarily shut-in production in response to historically low commodity prices.

Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs.

For the six months ended June 30, 2021, we drilled and cased 2.0 gross (2.0 net) operated wells, completed 6.0 gross (6.0 net) operated wells, and put online 6.0 gross (6.0 net) operated wells.

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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The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date.

Using the crude oil price for April 2021 of $61.35 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.

Using the crude oil price for July 2021 of $75.31 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test calculation would not have generated an impairment, holding all other inputs and factors constant.

In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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Although OPEC and Russia subsequently agreed to reduce production, downward pressure on prices continued for several months, particularly given concerns over the impacts of the economic downturn on demand.

We are unable to predict the future affects that these events will have on our business and financial condition due to numerous uncertainties, including the continuing severity and duration of the COVID-19 outbreak and the impacts that governmental or other actions taken to limit the extent and duration of the outbreak, in conjunction with economic conditions, will have on our business, demand for oil and natural gas, and oil and natural gas prices.

The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions cannot be predicted, nor can the impact on our customers, vendors and contractors.

As a consequence, beginning in March 2020, we realized lower revenue as a result of commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year.

Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices to pre-pandemic levels.

Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions.

However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors.

As a consequence, we are unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020.

Furthermore, the health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions remain concerns and cannot be predicted, nor can the impact on our customers, vendors and contractors.

Any material effect on these parties could adversely impact us.

These and other factors could affect our operations, earnings and cash flows and could cause our results to not be comparable to those of the same period in previous years.

For example, in 2020, we realized lower revenue as a result of commodity price declines, which began in March 2020.

In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020, which further contributed to lower revenues that year.

Additionally, we incurred ceiling test impairments in 2020, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

The results presented in this Form 10-Q are not necessarily indicative of future operating results.

For further information regarding the actual and potential impacts of COVID-19 on us, see “Risk Factors” in Item 1A of our 2020 Annual Report on Form 10-K.

For further information regarding the actual and potential impacts of COVID-19 on us, see “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020.

Senior Revolving Credit Facility

On May 10, 2021, we entered into the Fourth Amendment to Senior Secured Revolving Credit Agreement (the Fourth Amendment) which reduces the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021.

On May 10, 2021, we entered into the Fourth Amendment to Senior Secured Revolving Credit Agreement (the Fourth Amendment) which reduced the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021.

The Fourth Amendment also, among other things, (i) increased interest margins to 2.00% to 3.00% for ABR-based loans and 3.00% to 4.00% for Eurodollar-based loans, (ii) amended the covenant relating to the minimum mortgaged total value of proved borrowing base properties to increase the value from 90% to 95%, (iii) provides for direct reductions in the borrowing base in the event of asset dispositions in excess of $1.0 million per fiscal year or swap terminations and (iv) revised certain covenants and covenant-related baskets including, but not limited to, adding covenants prohibiting the designation of unrestricted subsidiaries and requiring prior consent from the lenders regarding asset dispositions or swap terminations in excess of the greater of $7.5 million or 3.5% of the then effective borrowing base.

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In March 2020, the World Health Organization declared the outbreak of COVID-19 a pandemic.

In 2020, the COVID - 19 outbreak and associated government restrictions significantly impacted economic activity and markets and dramatically reduced demand for oil and natural gas at the same time that supply was maintained at high levels due to a price and market share war involving the OPEC/Saudi Arabia and Russia, all of which adversely impacted the prices we received for our production.

Thus, in 2020, we realized lower revenue as a result of these commodity price declines, which began in March 2020.

In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020, which further contributed to lower revenues that year.

Additionally, we incurred ceiling test impairments during 2020, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

Continued 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.

received for our production.

As a consequence, beginning in March 2020, we realized lower revenue as a result of these commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year.

Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand of oil and natural gas and increases in oil and natural gas prices to pre-pandemic levels.

Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions.

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 the same sorts of factors that negatively impacted prices during 2020.

Actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the U.S.

or global financial system and markets and an economic contraction either regionally or worldwide, resulting from current efforts to contain the COVID-19 coronavirus or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production, adversely impacting our ability to comply with covenants in our Senior Credit Agreement or causing our lenders to further reduce the borrowing base under our Senior Credit Agreement.

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We expect to spend approximately $40.0 million to $50.0 million on drilling, completion, support infrastructure and other capital costs during 2021.

These near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations and, if needed, borrowings under our Senior Credit Agreement, which has a current borrowing base of $190.0 million, which is scheduled to be reduced to $185.0 million on June 1, 2021 and to $175.0 million on September 1, 2021 pursuant to the Fourth Amendment to our Senior Credit Agreement, as discussed in greater detail above.

These near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations and, if needed, borrowings under our Senior Credit Agreement, which has a current borrowing base of $185.0 million and which is scheduled to be reduced to $175.0 million on September 1, 2021 pursuant to the Fourth Amendment to our Senior Credit Agreement, as discussed in greater detail above.

Amounts borrowed under our Senior Credit Agreement will mature on October 8, 2024.

At March 31, 2021, we had $155.0 million of indebtedness outstanding and approximately $2.5 million letters of credit outstanding under our Senior Credit Agreement, resulting in $32.5 million of borrowing capacity under the current $190.0 million borrowing base.

At June 30, 2021, we had $163.0 million of indebtedness outstanding and approximately $1.9 million letters of credit outstanding under our Senior Credit Agreement, resulting in $20.1 million of borrowing capacity under the current $185.0 million borrowing base.

The next redetermination is scheduled for the fall of 2021.

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As part of our ongoing efforts to manage our business and liquidity, we are in regular contact with our lenders regarding matters relating to the Senior Credit Agreement, and we closely monitor our compliance with the various covenants under our Senior Credit Agreement, which include certain financial covenants, such as maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00.

As of March 31, 2021, afte r giving effect to the Third Amendment to Senior Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment), we were in compliance with the financial covenants under the Senior Credit Agreement.

As of June 30, 2021, afte r giving effect to the Third Amendment to Senior Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment), we were in compliance with the financial covenants under the Senior Credit Agreement.

We have periodically, including as recently as October 2020, obtained waivers or amendments to the financial covenants under our revolving credit agreements in circumstances where we anticipated that it might be challenging for us to comply with them for a particular period of time.

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As a consequence, we endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time.

For instance, depressed oil and natural gas prices during 2020 and our decision to temporarily shut-in a portion of our production in response to market conditions adversely impacted our cash flows, which, combined with cash requirements associated with capital-intensive oil and gas development projects undertaken in late 2019 and early 2020, led to challenges in our compliance with the Current Ratio under the Senior Credit Agreement for the fiscal quarter ended June 30, 2020.

For instance, depressed oil and natural gas prices during 2020 and

our decision to temporarily shut-in a portion of our production in response to market conditions adversely impacted our cash flows, which, combined with cash requirements associated with capital-intensive oil and gas development projects undertaken in late 2019 and early 2020, led to challenges in our compliance with the Current Ratio under the Senior Credit Agreement for the fiscal quarter ended June 30, 2020.

Thus, o n July 31, 2020, we secured a waiver in which the lenders consented to waive maintenance of the Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020.

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Similarly, in prior years, we have also obtained waivers and amendments for other financial covenant violations.

For instance, our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in

West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin.

For instance, our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin.

Our drilling activities once we acquired these assets required significant capital expenditure outlays to replenish production and related EBITDA from the divested producing properties.

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When commodity prices decline significantly, as they did in 2020, our ability to finance our capital budget and operations may be adversely impacted.

We employ derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices, however, the total volumes we typically hedge are less than our expected production, vary from period to period based on our view of current and future market conditions and generally extend up to only approximately 30 months.

We employ derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices, however, the total volumes we typically hedge are less than our

expected production, vary from period to period based on our view of current and future market conditions and generally extend up to only approximately 30 months.

These limitations result in our liquidity being susceptible to commodity price declines in the near term and, in particular, if such prices decline for a sustained period of time.

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Our future capital resources and liquidity depend 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

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 borrowing capacity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage.

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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.

During the three months ended March 31, 2021, operating cash flows and proceeds from divested properties funded our capital expenditures program and net repayments of borrowings under our Senior Credit Agreement.

During the six months ended June 30, 2021, operating cash flows and net borrowings under our Senior Credit Agreement funded our capital expenditures program.

See “ Results of Operations ” for a review of the impact of prices and volumes on operating revenues.

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

Three Months Ended

Six Months Ended

Cash flows provided by (used in) operating activities

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Operating Activities.

Net cash flows provided by operating activities for the three months ended March 31, 2021 and 2020 were $13.4 million and $12.3 million, respectively.

Operating cash flows for the three months ended March 31, 2021 increased slightly between the first three months of 2021 and 2020.

Our average realized price increase of approximately $15.34 per Boe contributed to higher total operating revenues in 2021 which were partially offset by payments on derivative settlements in 2021.

Operating cash flows for the three months ended March 31, 2020 increased from the comparable prior year due to decreases in our operating expenses associated with our focus on efficiencies and cost savings and a decrease in interest expense associated with lower outstanding debt due to our chapter 11 bankruptcy.

These decreases in expenditures were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices.

Net cash flows provided by operating activities for the six months ended June 30, 2021 and 2020 were $29.1 million and $43.1 million, respectively.

Operating cash flows for the six months ended June 30, 2021 decreased from the six months ended June 30, 2020 due to realized losses from derivative contracts incurred in the six months ended June 30, 2021 as a result of increased commodity prices.

In addition, realized gains from derivative contracts were higher in the six months ended June 30, 2020, as that period included the early termination of certain derivative contracts.

During the six months ended June 30, 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $16.3 million during the period.

The decrease to current period operating cash flows was partially offset by our average realized price increase of approximately $22.47 per Boe which contributed to higher oil and natural gas revenues in 2021.

Operating cash flows for the six months ended June 30, 2020 increased from the six months ended June 30, 2019 due to decreases in our operating expenses associated with our focus on efficiencies and cost savings and a decrease in

interest expense associated with lower outstanding debt due to our chapter 11 bankruptcy.

In addition, realized gains from derivative contracts were higher in the six months ended June 30, 2020, which included the early termination of certain derivative contracts.

These increases to operating cash flows in 2020 were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices and lower production volumes.

Investing Activities.

Net cash flows used in investing activities for the three months ended March 31, 2021 and 2020 were approximately $12.7 million and $47.6 million, respectively.

During the three months ended March 31, 2021, we spent $13.8 million on oil and natural gas capital expenditures, of which $10.8 million related to drilling and completion costs and $2.2 million related to the development of our treating equipment and gathering support infrastructure.

Net cash flows used in investing activities for the six months ended June 30, 2021 and 2020 were approximately $36.7 million and $90.2 million, respectively.

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.

During the three months ended March 31, 2020, we spent $48.2 million on oil and natural gas capital expenditures, of which $26.0 million related to drilling and completion costs and $21.8 million related to the development of our treating equipment and our gathering support infrastructure.

During the six months ended June 30, 2020, we spent $91.2 million on oil and natural gas capital expenditures, of which $61.2 million related to drilling and completion costs and $29.0 million related to the development of our treating equipment and our gathering support infrastructure.

We received $0.5 million in proceeds from the sale of oil and natural gas properties.

In addition, we received $0.5 million in insurance proceeds associated with a casualty loss on our support infrastructure.

Financing Activities.

Net cash flows used in financing activities for the three months ended March 31, 2021 was $3.3 million.

Net cash flow provided by financing activities for the three months ended March 31, 2020 was $26.0 million.

During the three months ended March 31, 2021, we used cash flows from operations to make net repayments of $3.0 million on our Senior Credit Agreement.

During the three months ended March 31, 2020, net borrowings of $26.0 million under our Senior Credit Agreement were used to fund our drilling and completions program and the development of our treating equipment and gathering support facilities.

Net cash flows provided by financing activities for the six months ended June 30, 2021 and 2020 were approximately $4.7 million and $37.2 million, respectively.

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.

During the six months ended June 30, 2020, net borrowings of $35.0 million under our Senior Credit Agreement were used to fund our drilling and completions program and the development of our treating equipment and gathering support facilities.

We also borrowed $2.2 million under the Paycheck Protection Plan Loan to fund payroll costs, rent and utilities.

Senior Revolving Credit Facility

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We may be required to make mandatory prepayments of the outstanding borrowings under the Senior Credit Agreement in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations.

Amounts outstanding under the Senior Credit Agreement are guaranteed by our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of us and our subsidiaries.

Amounts outstanding

under the Senior Credit Agreement are guaranteed by our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of us and our subsidiaries.

The Senior Credit Agreement contains certain events of default, including non-payment;

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Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

On May 10, 2021, we entered into the Fourth Amendment which reduces the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021.

On May 10, 2021, we entered into the Fourth Amendment which reduced the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021.

As of March 31, 2021, after giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

As of June 30, 2021, after giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

Paycheck Protection Program Loan

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Under the terms of the CARES Act, we can apply for and be granted forgiveness for all or a portion of the PPP Loan.

Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds in accordance with the terms of the CARES Act during the covered period after loan origination and the maintenance or achievement of certain employee levels.

We believe we are eligible for, and intend to pursue, forgiveness of the PPP Loan in accordance with the requirements and limitations under the CARES Act;

Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds in accordance with

the terms of the CARES Act during the covered period after loan origination and the maintenance or achievement of certain employee levels.

We believe we are eligible for, and are pursuing, forgiveness of the PPP Loan in accordance with the requirements and limitations under the CARES Act;

however, no assurance can be provided that forgiveness of any portion of the PPP Loan will be obtained.

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Results of Operations

Three Months Ended March 31, 2021 and 2020

We reported a net loss of $33.4 million and net income of $114.5 million for the three months ended March 31, 2021 and 2020, respectively.

Three Months Ended June 30, 2021 and 2020

We reported a net loss of $33.9 million and $127.3 million for the three months ended June 30, 2021 and 2020, respectively.

The table included below sets forth financial information for the periods presented.

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Accretion expense

Full cost ceiling impairment

Other income (expenses):

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Total MBoe (1)

Average daily production – Boe/d (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

Restructuring

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 $64.1 million and $18.0 million for the three months ended June 30, 2021 and 2020, respectively.

The increase in revenues in the most recent period is primarily attributable to an approximate $31.35 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, 2021 and 2020, production averaged 15,571 Boe/d and 14,264 Boe/d, respectively.

Our average daily production increased in the three months ended June 30, 2021 when compared to the same period in the prior year due to new production brought online as a result of our 2021 capital program as well as production from wells brought back online that were shut-in during May and June 2020 when historically low commodity prices occurred, which was partially offset by third-party processing curtailments and facility upgrades and repairs in the current year period.

Lease operating expenses were $10.2 million and $10.3 million for the three months ended June 30, 2021 and 2020, respectively.

On a per unit basis, lease operating expenses were $7.18 per Boe and $7.94 per Boe for the three months ended June 30, 2021 and 2020, respectively.

The decrease in lease operating expenses in 2021 results from operational efficiencies decreasing our per unit costs.

Workover and other expenses were $0.8 million and $0.5 million for the three months ended June 30, 2021 and 2020, respectively.

On a per unit basis, workover and other expenses were $0.54 per Boe and $0.42 per Boe for the three months ended June 30, 2021 and 2020, respectively.

The increased workover and other expenses in 2021 relate to more significant workover projects undertaken in the current year.

Taxes other than income were $2.9 million and $1.5 million for the three months ended June 30, 2021 and 2020, respectively.

Most production taxes are based on realized prices at the wellhead.

As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease.

On a per unit basis, taxes other than income were $2.06 per Boe and $1.15 per Boe for the three months ended June 30, 2021 and 2020, respectively.

Gathering and other expenses were $14.3 million and $15.2 million for the three months ended June 30, 2021 and 2020, respectively.

Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure.

Approximately $4.6 million and $2.3 million for the three months ended June 30, 2021 and 2020, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production.

Gathering and marketing fees increased in 2021 as we marketed higher quantities of sour gas production to third parties in the current year period.

Approximately $9.7 million and $9.5 million for the three months ended June 30, 2021 and 2020, respectively, relate to operating expenses on our treating equipment and gathering support facilities.

The increase in treating equipment and gathering support facilities expenses in 2021 results from higher chemical costs to improve the quality of treated oil, which were partially offset by lower operating expenses associated with our treating equipment, as fewer sour gas production volumes were processed through our hydrogen sulfide treating plant in the current year period.

Also included are $3.4 million of rig stacking charges for the three months ended June 30, 2020.

Restructuring expense was approximately $2.2 million for the three months ended June 30, 2020.

During the three months ended June 30, 2020, we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our workforce due to efforts to improve efficiencies and go forward costs.

In May 2020, in furtherance of the consolidation into one corporate office, we exercised a one-time early termination option under the lease agreement for our office space in Denver, Colorado.

General and administrative expense was $3.5 million and $4.5 million for the three months ended June 30, 2021 and 2020, respectively.

The reduction in general and administrative expense in the current period is associated with a decrease in professional fees and information technology costs incurred when compared to the prior year.

On a per unit basis, general and administrative expenses were $2.50 per Boe and $3.45 per Boe for the three months ended June 30, 2021 and 2020, 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 $11.0 million and $14.0 million for the three months ended June 30, 2021 and 2020, respectively.

On a per unit basis, depletion expense was $7.77 per Boe and $10.79 per Boe for the three months ended June 30, 2021 and 2020, respectively.

The lower depletion rate in the 2021 is attributable to the change in our depletable base as a result of full cost ceiling test impairments incurred in 2020.

Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling”, based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves.

Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense.

At June 30, 2020, we recorded a full cost ceiling impairment of $60.1 million.

The ceiling test impairment was primarily driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, from $55.96 per barrel at March 31, 2020 to $47.37 per barrel at June 30, 2020.

This average price decline was partially offset by favorable differentials and lower operating expenses.

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, 2021, we had a $1.8 million derivative asset, $1.3 million of which was classified as current, and we had a $86.6 million derivative liability, $71.4 million of which was classified as current.

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) for the three months ended June 30, 2021.

For the three months ended June 30, 2020, we recorded a net derivative loss of $34.8 million ($67.2 million net unrealized loss and $32.4 million net realized gain on settled and early terminated contracts).

During the three months ended June 30, 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received proceeds of approximately $16.4 million, which were included in the $32.4 million net realized gains for the period.

Six Months Ended June 30, 2021 and 2020

We reported a net loss of $67.3 million and $12.8 million for the six months ended June 30, 2021 and 2020, 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

Restructuring

General and administrative:

General and administrative

Stock-based compensation

Depletion, depreciation and accretion:

Depletion – Full cost

Depreciation – Other

Accretion expense

Full cost ceiling impairment

Other income (expenses):

Net gain (loss) on derivative contracts

Interest expense and other

Natural Gas - MMcf

Natural gas liquids – MBbls

Total MBoe (1)

Average daily production – Boe (1)

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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 $55.3 million and $47.0 million for the three months ended March 31, 2021 and 2020, respectively.

For the three months ended March 31 2021 and 2020, production averaged 14,333 Boe/d and 18,791 Boe/d, respectively.

Our average daily oil, natural gas and natural gas liquids production decreased in the first three months ended March 31, 2021 when compared to the same period in the prior year primarily due to production declines in our non-core areas, which were partially offset by increased production from our Monument Draw area, where new production came online as a result of our capital spending program.

Also contributing to decreased total production in the current year period is a temporary shut-in of production in February 2021 as a result of inclement weather.

The estimated production decrease associated with this temporary shut-in was approximately 1,300 Boe/d for the first three months of 2021.

In addition, in December 2020, we divested properties that produced approximately 800 Boe/d during the three months ended March 31, 2020.

Average realized prices (excluding the effects of hedging arrangements) were $42.84 per Boe and $27.50 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Oil, natural gas and natural gas liquids revenues were $119.4 million and $65.1 million for the six months ended June 30, 2021 and 2020, respectively.

The increase in revenues in the most recent period is primarily attributable to an approximate $22.47 per Boe increase in our average realized prices (excluding the effects of hedging arrangements).

Lease operating expenses were $9.5 million and $12.5 million for the three months ended March 31, 2021 and 2020, respectively.

For the six months ended June 30, 2021 and 2020, production averaged 14,956 Boe/d and 16,527 Boe/d, respectively.

In February 2021, we temporarily shut-in production due to inclement weather.

In May and June 2020, we temporarily shut-in production in response to historically low commodity prices.

Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs.

Lease operating expenses were $19.6 million and $22.8 million for the six months ended June 30, 2021 and 2020, respectively.

On a per unit basis, lease operating expenses were $7.25 per Boe and $7.58 per Boe for the six months ended June 30, 2021 and 2020, respectively.

The decrease in lease operating expenses in 2021 results from decreased salt water disposal costs due to lower production volumes and less produced water.

On a per unit basis, lease operating expenses were $7.34 per Boe and $7.30 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Workover and other expenses were $0.6 million and $1.3 million for the three months ended March 31, 2021 and 2020, respectively.

On a per unit basis, workover and other expenses were $0.43 per Boe and $0.77 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Workover and other expenses were $1.3 million and $1.9 million for the six months ended June 30, 2021 and 2020, respectively.

On a per unit basis, workover and other expenses were $0.49 per Boe and $0.62 per Boe for the six months ended June 30, 2021 and 2020, respectively.

The decreased workover and other expenses in 2021 relate to preventive operational measures previously undertaken to mitigate potential future failures in producing wells, continued improvements in well and completion designs, and cost reductions for materials and services.

Taxes other than income were $3.2 million and $2.9 million for the three months ended March 31, 2021 and 2020, respectively.

This decrease is partially offset by more significant workover projects undertaken in the second quarter of 2021.

Taxes other than income were $6.1 million and $4.4 million for the six months ended June 30, 2021 and 2020, respectively.

Most production taxes are based on realized prices at the wellhead.

As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease.

On a per unit basis, taxes other than income were $2.47 per Boe and $1.70 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Gathering and other expenses were $13.2 million and $10.5 million for the three months ended March 31, 2021 and 2020, respectively.

On a per unit basis, taxes other than income were $2.25 per Boe and $1.47 per Boe for the six months ended June 30, 2021 and 2020, respectively.

Gathering and other expenses were $27.5 million and $25.8 million for the six months ended June 30, 2021 and 2020, respectively.

Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure.

Approximately $4.0 million and $2.9 million for the three months ended March 31, 2021 and 2020, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production.

Approximately $8.6 million and $5.2 million for the six months ended June 30, 2021 and 2020, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production.

Gathering and marketing fees increased in 2021 as we marketed higher quantities of sour gas production to third parties in the current year period.

Approximately $9.2 million and $7.6 million for the three months ended March 31, 2021 and 2020, respectively, relate to operating expenses on our treating equipment and gathering support facilities.

Approximately $18.9 million and $17.2 million for the six months ended June 30, 2021 and 2020, respectively, relate to operating expenses on our treating equipment and gathering support facilities.

The increase in treating equipment and gathering support facilities expenses in 2021 results from higher electricity and buy back fuel costs incurred as a result of inclement weather in February 2021 and higher chemical costs to improve the quality of treated oil, which were partially offset by lower operating expenses associated with our treating equipment, as fewer sour gas production volumes were processed through our hydrogen sulfide treating plant in the current year period.

Restructuring expense was approximately $0.4 million for the three months ended March 31, 2020.

During the three months ended March 31, 2020, we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our workforce due to efforts to improve efficiencies and go forward costs.

General and administrative expense was $4.2 million and $3.5 million for the three months ended March 31, 2021 and 2020, respectively.

In late March 2020, due to changes in market conditions and decreased commodity prices, we determined that previously accrued discretionary cash incentives related to 2019 would not be paid, causing a $1.6 million reduction to general and administrative expense for the period.

On a per unit basis, general and administrative expenses were $3.28 per Boe and $2.03 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Stock-based compensation expense was $0.6 million and $0.4 million for the three months ended March 31, 2021 and 2020, respectively.

Stock based compensation expense increased in the current period related to awards granted during the first three months of 2020.

Also included are $3.4 million of rig stacking charges for the six months ended June 30, 2020.

Restructuring expense was approximately $2.6 million for the six months ended June 30, 2020.

During the six months ended June 30, 2020, we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our workforce due to efforts to improve efficiencies and go forward costs.

In May 2020, in furtherance of the consolidation into one corporate office, we exercised a one-time early termination option under the lease agreement for our office space in Denver, Colorado.

General and administrative expense was $7.8 million and $8.0 million for the six months ended June 30, 2021 and 2020, respectively.

The reduction in general and administrative expense in the current year period is associated with a decrease in professional fees and information technology costs.

These reductions were partial offset by an increase in payroll costs, as the 2020 period included a $1.6 million deduction to general and administrative expenses related to discretionary cash incentives.

In late March 2020, due to changes in market conditions and decreased commodity prices,

we determined that previously accrued discretionary cash incentives related to 2019 would not be paid, causing a $1.6 million reduction to general and administrative expense in the 2020 period.

On a per unit basis, general and administrative expenses were $2.87 per Boe and $2.64 per Boe for the six months ended June 30, 2021 and 2020, respectively.

The increase in general and administrative expenses on a per unit basis is attributed to the reduction in produced volumes between the periods.

Depletion expense was $10.3 million and $17.6 million for the three months ended March 31, 2021 and 2020, respectively.

On a per unit basis, depletion expense was $8.02 per Boe and $10.29 per Boe for the three months ended March 31, 2021 and 2020, respectively.

The lower depletion rate in the 2021 is attributable to the change in our depletable base as a result of full cost ceiling test impairments incurred in 2020.

We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production.

Depletion expense was $21.4 million and $31.6 million for the six months ended June 30, 2021 and 2020, respectively.

On a per unit basis, depletion expense was $7.89 per Boe and $10.51 per Boe for the six months ended June 30, 2021 and 2020, respectively.

The lower depletion rate in 2021 is attributable to the change in our depletable base as a result of full cost ceiling test impairments incurred in 2020.

Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense.

At June 30, 2020, we recorded a full cost ceiling impairment of $60.1 million.

This average price decline was partially offset by favorable differentials and lower operating expenses.

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 March 31, 2021, we had a $1.5 million derivative asset, $0.7 million of which was classified as current, and we had a $51.4 million derivative liability, $42.4 million of which was classified as current.

We recorded a net derivative loss of $45.7 million ($36.0 million net unrealized loss and $9.7 million net realized loss on settled and early terminated contracts) for the three months ended March 31, 2021.

For the three months ended March 31, 2020, we recorded a net derivative gain of $118.3 million ($112.4 million net unrealized gain and $5.9 million net realized gain on settled and early terminated contracts).

Interest expense and other was $1.4 million and $1.6 million for the three months ended March 31, 2021 and 2020, respectively.

Interest expense decreased during the three months ended March 31, 2021 as compared to the prior year period due to lower interest rates incurred on outstanding borrowings under our Senior Credit Agreement.

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) for the six months ended June 30, 2021.

For the six months ended June 30, 2020, we recorded a net derivative gain of $83.5 million ($45.2 million net unrealized gain and $38.3 million net realized gain on settled and early terminated contracts).

Recently Issued Accounting Pronouncements

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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