Item 2. Management’s Discussion and Analysis
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations for the three and six months ended June 30, 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. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see “ Special note regarding forward-looking statements .”
Overview
We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas. As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive long-term economics.
Our total operating revenues for the first six months of 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. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding, developing and producing oil and natural gas reserves at economical costs are critical to our long-term success.
Oil and natural gas prices are inherently volatile and sustained lower commodity prices could result in impairment charges under our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the crude oil price for 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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Recent Developments
Risk and Uncertainties
We are continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on our business, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including implementing various measures to ensure the continued operation of our business in a safe and secure manner. In 2020, COVID-19 and governmental actions to contain the pandemic contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war involving the Organization of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels. Although OPEC and Russia subsequently agreed to reduce production, downward pressure on prices continued for several months, particularly given concerns over the impacts of the economic downturn on demand. As a consequence, beginning in March 2020, we realized lower revenue as a result of commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year. Additionally, 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. 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 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 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.
Capital Resources and Liquidity
In March 2020, the World Health Organization declared the outbreak of COVID-19 a pandemic. In 2020, the COVID - 19 outbreak and associated government restrictions significantly impacted economic activity and markets and 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
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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. 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, 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. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in, and borrowing capacity under, our Senior Credit Agreement.
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 $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 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. If our borrowing base is further reduced upon a redetermination, our resulting liquidity could be insufficient to fund our business, operations and planned capital expenditures and the reduction could result in a borrowing base deficiency, which would require us to repay any amount outstanding in excess of the borrowing base.
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 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. 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 Senior Credit Agreement. 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
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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. In conjunction with the fall 2020 borrowing base redetermination process, and due to a decline in the value associated with our derivative contracts, we pursued additional relief from our lenders in regards to the Current Ratio. On October 29, 2020, in the Third Amendment, the lenders waived maintenance with the Current Ratio for the fiscal quarter ending September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.
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. Our drilling activities once we acquired these assets required significant capital expenditure outlays to replenish production and related EBITDA from the divested producing properties. These and other factors adversely impacted our ability to comply with our debt covenants under the predecessor credit agreement by reducing our production, reserves and EBITDA on a current and a pro forma historical basis, while making us more susceptible to fluctuations in performance and compliance more challenging. In addition, we encountered certain operational difficulties that impacted our ability to comply at the time, including elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells and limited and expensive treatment and transportation options. Severance payments to executives in 2019 also impacted our ability to comply with our financial covenants.
In short, historically, our lenders have provided us with the covenant relief we have sought to the extent it was necessary to manage through near-term business and operational challenges as we pursued our longer-term business objectives; however, there is no assurance that they will be amenable to providing any such relief in the future, should it become necessary. Further, there is some evidence that credit is becoming more challenging for oil and gas companies generally, and for us in particular, to secure. As noted previously, late last year, Bank of Montreal, the primary lender under our Senior Credit Agreement, announced that it was exiting its U.S. energy investment banking business, a service line that is generally complementary to commercial banking service offerings. Bank of Montreal’s election to exit that line of business may be an indication of sentiment overall with regards to the business and investment banking environment affecting the U.S. oil and gas industry in the near term.
More specifically as it regards us, in our recent redetermination, the lenders under our Senior Credit Agreement have reduced our borrowing base to $185.0 million effective on June 1, 2021 and $175.0 million effective on September 1, 2021, and we agreed to some other modifications of the terms and covenants contained in our Senior Credit Agreement at the request of our lenders in the Fourth Amendment, as discussed in greater detail above. While we anticipate that we will be able to operate our business and maintain adequate liquidity within the limitations imposed by our Senior Credit Agreement, as amended, the loss of additional liquidity may prevent us from accelerating our drilling plans in an effort to manage our liquidity more closely. Additionally, reduced access to bank borrowings limits our flexibility in responding to unforeseen adverse events as well as our ability to pursue opportunities that might prove beneficial in the future. As noted elsewhere herein and our other filings with the Securities and Exchange Commission, many factors, including many that are beyond our control, affect our business and operations and may adversely impact our cash flows, liquidity and our ability to comply with the covenants under our Senior Credit Agreement. Consequently, there is no assurance that our expectations with regard to our capital needs or compliance with the covenants in the Senior Credit Agreement will prove accurate. In the event we are unable to maintain compliance, the lenders under our Senior Credit Agreement may be unwilling to provide us with the covenant relief we need. In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in securing alternative means of financing our business upon favorable terms or at all. If we are able to secure alternative financing, it may be more costly, provide less liquidity, or impose more restrictive covenants than our Senior Credit Agreement.
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
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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. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established under our hedges. Our Senior Credit Agreement contains minimum hedging requirements. Pursuant to the Third Amendment, we are required to hedge at least 65% of anticipated production from proved developed producing reserves through December 31, 2022. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.
Our future capital resources and liquidity depend on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We strive to maintain financial flexibility while pursuing our drilling plans and may access capital markets, pursue joint ventures, sell assets and engage in other transactions as necessary to, among other things, maintain borrowing capacity, 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 borrowing base is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.
Cash Flow
During the 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):
Six Months Ended
June 30,
2021
2020
Cash flows provided by (used in) operating activities
$
29,100
$
43,104
Cash flows provided by (used in) investing activities
(36,669)
(90,155)
Cash flows provided by (used in) financing activities
4,732
37,177
Net increase (decrease) in cash and cash equivalents
$
(2,837)
$
(9,874)
Operating Activities. 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
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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. 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. 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 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 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 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
On October 8, 2019, we entered into the Senior Credit Agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders. The Senior Credit Agreement, as amended, provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $185.0 million. A portion of the Senior Credit Agreement, in the amount of $25.0 million, is available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement is October 8, 2024. Redeterminations of the borrowing base occur semi-annually on May 1 and November 1, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 2.00% to 3.00% for ABR-based loans or at specified margins over LIBOR of 3.00% to 4.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement. These margins fluctuate based on our utilization of the facility.
We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty, except with respect to any break funding payments that may be payable pursuant to the terms of the Senior Credit Agreement. 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
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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; breaches of representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Credit Agreement also contains certain financial covenants, including 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.
On October 29, 2020, we entered into the Third Amendment. The Third Amendment, among other things, set the borrowing base to $190.0 million as of November 1, 2020. The Third Amendment also reduced the amount available for the issuance of letters of credit to $25.0 million and amended certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%. Additionally, the Third Amendment provided for new covenants that, among other things, require us to enter into swap agreements representing not less than 65% of our reasonably anticipated projected production from proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3.0 million of our uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days. 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 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.
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
On April 16, 2020, we entered into a promissory note (the PPP Loan) for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the U.S. Small Business Administration (SBA). Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date of April 16, 2022. As long as we make a timely application of forgiveness to the SBA, we are not required to make any payments under the PPP Loan until the forgiveness amount is communicated to us by the SBA.
We may elect, at our option, to prepay 20% or less of the borrowings outstanding under the PPP Loan without premium or penalty, and without notice. Prepayments of more than 20% of the outstanding borrowings require written advanced notice and payment of accrued interest. The PPP Loan contains certain events of default including non-payment, breach of representations and warranties, cross-defaults to other loans with the lender or to material indebtedness, voluntary or involuntary bankruptcy, judgments and change in control.
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
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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.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.
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Results of Operations
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.
Three Months Ended
June 30,
In thousands (except per unit and per Boe amounts)
2021
2020
Change
Net income (loss)
$
(33,929)
$
(127,316)
$
93,387
Operating revenues:
Oil
51,935
15,758
36,177
Natural gas
5,317
836
4,481
Natural gas liquids
6,851
1,437
5,414
Other
263
463
(200)
Operating expenses:
Production:
Lease operating
10,169
10,300
(131)
Workover and other
767
539
228
Taxes other than income
2,912
1,493
1,419
Gathering and other
14,331
15,228
(897)
Restructuring
—
2,162
(2,162)
General and administrative:
General and administrative
3,546
4,484
(938)
Stock-based compensation
485
786
(301)
Depletion, depreciation and accretion:
Depletion – Full cost
11,015
14,005
(2,990)
Depreciation – Other
105
232
(127)
Accretion expense
129
145
(16)
Full cost ceiling impairment
—
60,107
(60,107)
Other income (expenses):
Net gain (loss) on derivative contracts
(53,089)
(34,761)
(18,328)
Interest expense and other
(1,747)
(1,568)
(179)
Production:
Oil – MBbls
805
775
30
Natural Gas - MMcf
2,055
1,632
423
Natural gas liquids – MBbls
270
251
19
Total MBoe (1)
1,417
1,298
119
Average daily production – Boe/d (1)
15,571
14,264
1,307
Average price per unit (2) :
Oil price - Bbl
$
64.52
$
20.33
$
44.19
Natural gas price - Mcf
2.59
0.51
2.08
Natural gas liquids price - Bbl
25.37
5.73
19.64
Total per Boe (1)
45.24
13.89
31.35
Average cost per Boe:
Production:
Lease operating
$
7.18
$
7.94
$
(0.76)
Workover and other
0.54
0.42
0.12
Taxes other than income
2.06
1.15
0.91
Gathering and other
10.11
11.73
(1.62)
Restructuring
—
1.67
(1.67)
General and administrative:
General and administrative
2.50
3.45
(0.95)
Stock-based compensation
0.34
0.61
(0.27)
Depletion
7.77
10.79
(3.02)
(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio is based on energy equivalency, not price equivalency. The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil.
(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.
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Oil, natural gas and natural gas liquids revenues were $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
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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.
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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
June 30,
In thousands (except per unit and per Boe amounts)
2021
2020
Change
Net income (loss)
$
(67,304)
$
(12,825)
$
(54,479)
Operating revenues:
Oil
93,205
57,675
35,530
Natural gas
14,404
1,190
13,214
Natural gas liquids
11,760
6,190
5,570
Other
515
838
(323)
Operating expenses:
Production:
Lease operating
19,636
22,789
(3,153)
Workover and other
1,327
1,862
(535)
Taxes other than income
6,104
4,408
1,696
Gathering and other
27,502
25,775
1,727
Restructuring
—
2,580
(2,580)
General and administrative:
General and administrative
7,779
7,953
(174)
Stock-based compensation
1,079
1,173
(94)
Depletion, depreciation and accretion:
Depletion – Full cost
21,356
31,605
(10,249)
Depreciation – Other
231
513
(282)
Accretion expense
257
294
(37)
Full cost ceiling impairment
—
60,107
(60,107)
Other income (expenses):
Net gain (loss) on derivative contracts
(98,800)
83,538
(182,338)
Interest expense and other
(3,117)
(3,197)
80
Production:
Oil – MBbls
1,524
1,712
(188)
Natural Gas - MMcf
4,188
4,171
17
Natural gas liquids – MBbls
485
601
(116)
Total MBoe (1)
2,707
3,008
(301)
Average daily production – Boe (1)
14,956
16,527
(1,571)
Average price per unit (2) :
Oil price - Bbl
$
61.16
$
33.69
$
27.47
Natural gas price - Mcf
3.44
0.29
3.15
Natural gas liquids price - Bbl
24.25
10.30
13.95
Total per Boe (1)
44.10
21.63
22.47
Average cost per Boe:
Production:
Lease operating
$
7.25
$
7.58
$
(0.33)
Workover and other
0.49
0.62
(0.13)
Taxes other than income
2.25
1.47
0.78
Gathering and other
10.16
8.57
1.59
Restructuring
—
0.86
(0.86)
General and administrative:
General and administrative
2.87
2.64
0.23
Stock-based compensation
0.40
0.39
0.01
Depletion
7.89
10.51
(2.62)
(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio is based on energy equivalency, not price equivalency. The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil.
(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.
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Oil, natural gas and natural gas liquids revenues were $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). The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors. For the six months ended June 30, 2021 and 2020, production averaged 14,956 Boe/d and 16,527 Boe/d, respectively. 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.
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.
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. 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 $2.25 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 $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 $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. 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,
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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 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 $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.
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 economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations. At June 30, 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 $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). 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, which were included in the $38.3 million net realized gains for the period.
Recently Issued Accounting Pronouncements
We discuss recently adopted and issued accounting standards in Item 1. Condensed Consolidated Financial Statements (Unaudited) —Note 1, “ Financial Statement Presentation .”
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.