GOODRICH PETROLEUM CORPORATION CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with our management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), concerning our operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and natural gas properties, marketing and midstream activities, and also include those statements accompanied by or that otherwise include the words "may," "could," "believes," "expects," "anticipates," "intends," "estimates," "projects," "predicts," "target," "goal," "plans," "objective," "potential," "should," or similar expressions or variations on such expressions that convey the uncertainty of future events or outcomes. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.
These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following:
• public health crises, such as the Coronavirus Disease 2019 ("COVID-19")
outbreak in 2020 and 2021;
• the market prices of oil and natural gas;
• volatility in the commodity-futures market;
• financial market conditions and availability of capital;
• future cash flows, credit availability and borrowings;
• sources of funding for exploration and development;
• our financial condition;
• our ability to repay our debt;
• the securities, capital or credit markets;
• planned capital expenditures;
• future drilling activity;
• uncertainties about the estimated quantities of our oil and natural gas
reserves and production from our wells;
• the creditworthiness of our hedging counter-parties and the effect of our
hedging arrangements;
• litigation matters;
• pursuit of potential future acquisition opportunities;
• general economic conditions, either nationally or in the jurisdictions in
which we are doing business;
• legislative or regulatory changes, including retroactive royalty or production
tax regimes, hydraulic-fracturing regulation, drilling and permitting
regulations, derivatives reform, changes in state and federal corporate taxes,
environmental regulation, environmental risks and liability under federal,
state and foreign and local environmental laws and regulations?
• the creditworthiness of our financial counter-parties and operation partners;
and
• other factors discussed below and elsewhere in this Quarterly Report on Form
10-Q and in our other public filings, press releases and discussions with our
management.
For additional information regarding known material factors that could cause our
actual results to differ from projected results please read the rest of this
Quarterly Report on Form 10-Q and Part I, "Item 1A. Risk Factors" in our Annual
Report on Form 10-K for the year ended December 31, 2020 .
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Table of Contents OverviewGoodrich Petroleum Corporation ("Goodrich" and, together with its subsidiary,Goodrich Petroleum Company, L.L.C. (the "Subsidiary"), "we," "our," or the "Company") is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i)Northwest Louisiana andEast Texas , which includes the Haynesville Shale Trend, (ii)Southwest Mississippi andSoutheast Louisiana , which includes the Tuscaloosa Marine Shale Trend ("TMS"), and (iii)South Texas , which includes the Eagle Ford Shale Trend. We seek to increase shareholder value by growing our oil and natural gas reserves, production, revenues and cash flow from operating activities ("operating cash flow"). In our opinion, on a long term basis, growth in oil and natural gas reserves, cash flow and production on a cost-effective basis are the most important indicators of performance success for an independent oil and natural gas company. Management strives to increase our oil and natural gas reserves, production and cash flow through exploration and development activities. We develop an annual capital expenditure budget, which is reviewed and approved by our Board of Directors (the "Board") on a quarterly basis and revised throughout the year as circumstances warrant. When establishing our capital expenditure budget, we take into consideration our projected operating cash flow, commodity prices for oil and natural gas and externally available sources of financing, such as bank debt, asset divestitures, issuance of debt and equity securities and strategic joint-ventures. Our revenues and operating cash flow depend on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and natural gas. The prices we receive for our production are largely beyond our control. We have historically been able to hedge our natural gas production at prices that are higher than current strip prices in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow. However, depending on volatility in the commodity price environment, our ability to enter into comparable derivative arrangements may be more limited. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty and turmoil in the oil and gas industry. Throughout 2020, the effect of COVID-19 significantly lowered the demand for and prices of crude oil which resulted in an oversupply of crude oil with significant downward pressure on commodity prices for much of the year. During the first half of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, the effect of the COVID-19 pandemic and related economic, business and market disruptions remain uncertain. The most direct and immediate impact that the Company experienced from the COVID-19 pandemic was decreased demand for and prices of crude oil. While the prices of and demand for crude oil have recovered from the lows seen in the initial stages of the pandemic, further outbreaks or the emergence of new strains of the virus could result in the reimposition of federal, state and local regulations directing individuals to stay at home, limiting travel, requiring facility closures and imposing similar measures. Widespread reimposition of these or similar restrictions could result in reductions in the prices of and demand for crude oil, as well as logistic constraints, increases in our costs, workforce shortages and unavailability of raw materials. Because we predominately produce natural gas, and natural gas has not been impacted by the same market forces as crude oil, we have experienced less of an impact from COVID-19 than many of our peers. However, the scope and length of the COVID-19 pandemic and the ultimate effect on the price of natural gas cannot be determined, and we could be adversely affected in future periods. To mitigate the effects of the downturn in commodity prices due to the effects of COVID-19, we initiated a company-wide cost reduction program eliminating outside services that are not core to our business, on which we continue to focus, as well as a reduction in headcount year over year. Additionally, we have substantial volumes of our production hedged through the first quarter of 2022, and to a lesser extent, volumes hedged fromApril 2022 toMarch 2023 . As a result of the steps we have taken to enhance our liquidity, we anticipate our cash on hand, cash from operations and our available borrowing capacity under our 2019 Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements into 2022.
We remain committed to the following priorities while navigating through the COVID-19 pandemic:
• Ensuring the health and safety of our employees and the contractors that
provide services to us;
• Continuing to monitor the impact the COVID-19 pandemic has on demand for our
products in addition to related commodity price impacts in order to adjust
our business accordingly; and
• Ensuring we emerge from the COVID-19 pandemic in as strong of a position as
possible as we continue to move forward with our long-term strategies.
While the COVID-19 pandemic may potentially adversely affect our operations or employees' health in the future, as of the date of this filing, we have not experienced a significant disruption to our operations and we have implemented a contingency plan, with employees working remotely where possible and in compliance with governmental orders andCenters for Disease Control and Prevention recommendations. Primary Operating Areas Haynesville Shale Trend We have acquired or farmed-in leases totaling approximately 56,000 gross (32,000 net) acres as ofSeptember 30, 2021 in the Haynesville Shale Trend. We completed and produced 4 gross (2.2 net) new wells in the third quarter of 2021 and had 8 gross (2.3 net) wells in the drilling or completions phase as ofSeptember 30, 2021 . Our Haynesville Shale Trend drilling activities are currently located in leasehold areas inCaddo ,DeSoto andRed River parishes,Louisiana . Our net production volumes from our Haynesville Shale Trend wells represented approximately 99% of our total equivalent production on a Mcfe basis and substantially all of our natural gas production for the third quarter of 2021. We are focusing on increasing our natural gas production volumes through increased drilling in the Haynesville Shale Trend, where we plan to focus all of our 2021 drilling efforts. Tuscaloosa Marine Shale Trend As ofSeptember 30, 2021 , we own approximately 48,000 gross (34,000 net) lease acres in the TMS, an oil shale play inSouthwest Mississippi andSouthwest Louisiana , which is predominately held by production. We have 2 gross (1.7 net) TMS wells drilled and awaiting completion. Our net production volumes from our TMS wells represented approximately 1% of our total equivalent production on a Mcfe basis and 99% of our total oil production for the third quarter of 2021. Despite no capital expenditures, we are seeking to maintain production through strategic expense workover operations in the TMS. 22
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Table of Contents Eagle Ford Shale Trend
We have retained approximately 4,300 net acres of undeveloped leasehold in the
Eagle Ford Shale Trend in
Results of Operations The items that had the most material financial effect on our net loss of$48.0 million and$55.0 million for the three and nine months endedSeptember 30, 2021 , compared to prior year respective periods, were higher losses on derivatives not designated as hedges, largely non-cash mark-to-market losses, of$77.4 million and$103.1 million , respectively. These higher losses were partially offset by no impairment expense in the current year and increased oil and natural gas revenues due to increased natural gas and oil prices and higher production from new wells brought online. The items that had the most material financial effect on our net loss of$16.4 million and$36.3 million for the three and nine months endedSeptember 30, 2020 , compared to prior respective periods, were the decrease in revenues as a result of a substantial drop in oil and natural gas prices for both the three and nine months endedSeptember 30, 2020 , a mark-to-market loss on unsettled derivative contracts driven by increased natural gas forward strip prices and an impairment expense. The following table reflects our summary operating information for the periods presented (in thousands, except for price and volume data). Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results. Revenues from Operations Three Months Ended September 30, Nine Months Ended September 30, (In thousands, except for price and average daily production data) 2021 2020 Variance 2021 2020 Variance Revenues: Natural gas$ 56,888 $ 20,167 $ 36,721 182 %$ 122,981 $ 60,370 $ 62,611 104 % Oil and condensate 1,845 1,296 549 42 % 5,727 4,547 1,180 26 % Natural gas, oil and condensate 58,733 21,463 37,270 174 % 128,708 64,917 63,791 98 % Net Production: Natural gas (Mmcf) 15,108 11,346 3,762
33 % 40,113 35,937 4,176 12 % Oil and condensate (MBbls)
26 33 (7 ) (21 )% 89 107 (18 ) (17 )%
Total (Mmcfe) 15,265 11,543 3,722 32 % 40,646 36,576 4,070 11 % Average daily production (Mcfe/d)
165,925 125,462 40,463 32 % 148,885 133,487 15,398 12 %
Average realized sales price
per unit:
Natural gas (per Mcf) $ 3.77 $ 1.78 $ 1.99 112 % $ 3.07 $ 1.68 $ 1.39 83 %
Natural gas (per Mcf)
including the effect of
realized gains/losses on
derivatives $ 2.94 $ 1.89 $ 1.05 56 % $ 2.70 $ 2.06 $ 0.64 31 %
Oil and condensate (per Bbl) $ 70.40 $ 39.63 $ 30.77 78 % $ 64.50 $ 42.76 $ 21.74 51 %
Oil and condensate (per Bbl)
including the effect of
realized gains/losses on
derivatives $ 70.40 $ 49.90 $ 20.50 41 % $ 64.25 $ 55.06 $ 9.19 17 %
Average realized price (per
Mcfe) $ 3.85 $ 1.86 $ 1.99 107 % $ 3.17 $ 1.77 $ 1.40 79 %
Natural gas, oil and condensate revenues increased by $37.3 million and $63.8
million , respectively, for the three and nine months ended September 30, 2021 ,
compared to the same periods in 2020. The increase was primarily driven by
higher realized natural gas and oil prices coupled with increased natural gas
production volumes. The rise in natural gas and oil prices increased revenues by
$23.6 million and $52.1 million , respectively, for the three and nine months
ended September 30, 2021 , and higher natural gas volumes had a $14.2 million and
$12.8 million impact on revenues for the three and nine months ended September
30, 2021 , respectively.
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Table of Contents Operating Expenses As described below, total operating expenses increased$2.1 million for the three months endedSeptember 30, 2021 and decreased$18.9 million for the nine months endedSeptember 30, 2021 , compared to the same periods in 2020. The increase in total operating expenses for the three months endedSeptember 30, 2021 was primarily due to expenses associated with higher production volumes, including lease operating expenses, production and other taxes, transportation and processing and depletion and amortization expense, partially offset by no impairment expense in 2021. The decrease in total operating expenses for the nine months endedSeptember 30, 2021 was primarily due to no impairment expense in 2021 and lower transportation and processing and general and administrative expense, partially offset by higher lease operating expenses due to increased production volumes. On a per unit basis, excluding the impact of impairment expense in 2020, operating costs decreased$0.15 and$0.23 per Mcfe for the three and nine months endedSeptember 30, 2021 , respectively, compared to the same periods in 2020. The year over year comparisons for operating expenses are discussed further below. Three Months Ended September 30, Nine Months Ended September 30, Operating Expenses (in thousands) 2021 2020 Variance 2021 2020 Variance Lease operating expenses$ 3,277 $ 2,831 $ 446
16 %
1,291 591 700 118 % 2,756 2,361 395 17 % Transportation and processing
4,811 4,336 475 11 % 13,457 14,586 (1,129 ) (8 )% Operating Expenses per Mcfe Lease operating expenses
$ 0.21 $ 0.25 $ (0.04 )
(16 )%
60 %
(16 )%$ 0.34 $ 0.41 $ (0.07 ) (17 )% Lease Operating Expense Lease operating expense ("LOE") increased$0.4 million and$1.0 million , respectively, for the three and nine months endedSeptember 30, 2021 , compared to the same periods in 2020. The increase in LOE is primarily attributed to an increase in production volumes and the number of producing wells in 2021 versus 2020 as well as additional workover expense for the nine months endedSeptember 30, 2021 . Per unit LOE was$0.21 per Mcfe and$0.26 per Mcfe for the three and nine months endedSeptember 30, 2021 , respectively, of which$0.02 per Mcfe was attributed to the$0.3 million in workover expense incurred in the three months endedSeptember 30, 2021 , and$0.04 per Mcfe was attributed to the$1.8 million in workover expense incurred in the nine months endedSeptember 30, 2021 . Production and Other Taxes Production and other taxes includes severance and ad valorem taxes. Severance taxes were$1.0 million and$2.0 million for the three and nine months endedSeptember 30, 2021 , respectively, and ad valorem taxes were$0.2 million and$0.7 million for the three and nine months endedSeptember 30, 2021 , respectively. Severance taxes increased$0.7 million and$0.6 million for the three and nine months endedSeptember 30, 2021 , respectively, compared to the same periods in 2020. The increase is primarily due to higher production volumes upon which the volumetric tax is based as wells have begun to incur severance tax inLouisiana after the exemption ended, partially offset by a lower severance tax rate inLouisiana . TheState of Louisiana has enacted an exemption from the existing 12.5% severance tax on oil and from the$0.125 per Mcf (fromJuly 1, 2019 throughJune 30, 2020 ),$0.0934 per Mcf (fromJuly 1, 2020 toJune 30, 2021 ) and$0.091 per Mcf (fromJuly 1, 2021 toJune 30, 2022 ) severance tax on natural gas for horizontal wells with production commencing afterJuly 31, 1994 . The exemption is applicable until the earlier of (i) 24 months from the date of first sale of production or (ii) payout of the well. All of our recently drilled, operated Haynesville Shale Trend wells inNorthwest Louisiana are benefiting from this exemption upon initial production. Ad valorem tax remained flat and decreased$0.2 million for the three and nine months endedSeptember 30, 2021 , respectively, compared to the same periods in 2020, due to more favorable tax calculation methodologies on certain of our properties with respective taxing agencies. 24
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Table of Contents Transportation and Processing Our natural gas production incurs substantially all of our transportation and processing expense. Transportation and processing expense for the three and nine months endedSeptember 30, 2021 increased$0.5 million and decreased$1.1 million , respectively, compared to the same periods in 2020. The increase in transportation and processing expense for the three months endedSeptember 30, 2021 was primarily due to increased production from our Haynesville Shale Trend wells, partially offset by more favorable rates contracted with third parties. The decrease in transportation and processing expense for the nine months endedSeptember 30, 2021 was primarily due to the more favorable rates contracted with third parties despite an increase in production volumes. Additionally, the mix of operated versus non-operated volumes impacts our transportation and processing expense as our operated natural gas volumes, particularly from our recent operated wells brought online, generally carry less transportation cost than those from wells we do not operate. Three Months Ended September 30, Nine Months Ended September 30, Operating Expenses (in thousands): 2021 2020 Variance 2021 2020 Variance Depreciation, depletion and amortization$ 13,389 $ 10,341 $ 3,048 29 %$ 35,671 $ 35,484 $ 187 1 % General and administrative 4,329 3,891 438 11 % 11,302 13,327 (2,025 ) (15 )% Impairment of oil and natural gas properties - 3,040 (3,040 )
(100 )% - 17,170 (17,170 ) (100 )% Other
4 (11 ) 15 136 % (183 ) (13 ) (170 ) (1308 )%
Operating Expenses per Mcfe
Depreciation, depletion and
amortization $ 0.88 $ 0.90 $ (0.02 ) (2 )% $ 0.88 $ 0.97 $ (0.09 ) (9 )%
General and administrative $ 0.28 $ 0.34 $ (0.06 ) (18 )% $ 0.28 $ 0.36 $ (0.08 ) (22 )%
Impairment of oil and natural
gas properties $ - $ 0.26 $ (0.26 ) (100 )% $ - $ 0.47 $ (0.47 ) (100 )%
Other $ - $ - $ - - % $ - $ - $ - - %
Depreciation, Depletion and Amortization ("DD&A")
DD&A expense increased$3.0 million and$0.2 million for the three and nine months endedSeptember 30, 2021 , respectively, compared to the same periods in 2020. The increase for the three months endedSeptember 30, 2021 was attributed to increased production volumes, partially offset by a lower per unit cost discussed below. The increase in DD&A expense for the nine months ended September, 2021 compared to the prior year period was attributed primarily to increased production volumes partially offset by a lower per unit cost based on the year-end 2020 and mid-year 2021 reserve reports, largely as a result of recognizing impairment expense of$36.1 million in the prior year.
Impairment Expense
The Full Cost Method ceiling test for the three and nine months
ended
General and Administrative ("G&A")
The Company recorded$4.3 million and$11.3 million in G&A expense for the three and nine months endedSeptember 30, 2021 , respectively, which included non-cash expenses for share-based compensation of$0.5 million and$1.2 million , respectively. G&A expense increased for the three months endedSeptember 30, 2021 by$0.4 million primarily due to higher bonus accruals due to better performance measures than target related to the annual and long-term incentive plans, partially offset by lower rent expense associated with a renegotiated lease for office space. For the nine months endedSeptember 30, 2021 , G&A expense decreased by$2.0 million compared to the same period in 2020 primarily due to reduced employee expenses including salaries and stock compensation expense as well as decreased rent expense, partially offset by a higher bonus accrual related to a the cash-based long-term incentive plan due to better performance measures than target for the current year. The Company recorded$3.9 million and$13.3 million in G&A expense for the three and nine months endedSeptember 30, 2020 , respectively, which included non-cash expenses of$1.0 million and$3.5 million , respectively, for share-based compensation. Other Operating Expenses
Other operating expense credits of
Other Income (Expense)
Three Months Ended September 30 , Nine Months Ended September 30 ,Other income (expense) (in thousands): 2021 2020 Variance 2021 2020 Variance Interest expense$ (2,232 ) $ (1,733 ) $ 499 29 %$ (6,255 ) $ (5,410 ) $ 845 16 % Interest income and other - 5 (5 ) (100 )% - 147 (147 ) (100 )% Loss on commodity derivatives not designated as hedges (77,369 ) (11,079 ) (66,290 ) (598 )% (103,111 ) (3,629 ) (99,482 ) (2741 )% Loss on early extinguishment of debt - - - - % (935 ) - (935 ) (100 )% Average funded borrowings adjusted for debt discount$ 124,403 $ 107,268 $ 17,135 16 %$ 119,068 $ 104,925 $ 14,143 13 % Average funded borrowings$ 127,168 $ 110,505 $ 16,663 15 %$ 121,934 $ 108,323 $ 13,611 13 % Interest Expense Interest expense for the three months endedSeptember 30, 2021 included$1.0 million incurred on the 2019 Senior Credit Facility (as defined below) and$1.2 million incurred on the Company's 13.50% Convertible Second Lien Senior Secured Notes due 2023 (the "2023 Second Lien Notes"). Interest expense for the nine months endedSeptember 30, 2021 included$3.0 million incurred on the 2019 Senior Credit Facility,$2.7 million incurred on the Company's 2023 Second Lien Notes and$0.5 million incurred on the Company's 13.50% Convertible Second Lien Senior Secured Notes due 2022 (the "2021/2022 Second Lien Notes") until exchanged onMarch 9, 2021 . The interest on the 2021/2022 Second Lien Notes and 2023 Second Lien Notes was all non-cash consisting of paid in-kind interest of$1.1 million , amortization of debt discount of$0.1 million and amortization of debt issuance costs of less than$0.1 million for the three months endedSeptember 30, 2021 , and paid in-kind interest of$2.7 million , amortization of debt discount of$0.4 million and amortization of debt issuance costs of$0.1 million for the nine months endedSeptember 30, 2021 . The interest on the 2019 Senior Credit Facility included$0.9 million and$2.6 million of interest payable in cash for the three and nine months endedSeptember 30, 2021 , respectively, and$0.1 million and$0.4 million of non-cash amortization of debt issuance costs for the three and nine months endedSeptember 30, 2021 , respectively. Interest expense for the three and nine months endedSeptember 30, 2020 reflected interest payable in cash of$1.0 million and$3.1 million , respectively, incurred on the 2019 Senior Credit Facility and non-cash interest of$0.7 million and$2.3 million , respectively, incurred primarily on the 2021/2022 Second Lien Notes, which included$0.5 million of paid in-kind interest and$0.2 million of amortization of debt discount and issuance costs for the three months endedSeptember 30, 2020 , and$1.4 million of paid in-kind interest and$0.9 million of amortization of debt discount and debt issuance costs for the nine months endedSeptember 30, 2020 . 25
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Table of Contents
Gain (Loss) on Commodity Derivatives Not Designated as Hedges
We produce and sell oil and natural gas into a market where prices are historically volatile. We enter into swap contracts, collars or other derivative agreements from time to time to manage our exposure to commodity price risk for a portion of our production. We do not designate our derivative contracts as hedges for accounting purposes. Consequently, the changes in our mark-to-market valuations are recorded directly to income or loss on our financial statements. The loss on commodity derivatives not designated as hedges of$77.4 million for the three months endedSeptember 30, 2021 was comprised of a mark-to-market loss of$64.9 million , representing the change of fair value on our open natural gas derivative contracts, and a$12.5 million loss on net cash settlements of natural gas derivative contracts. The loss on commodity derivatives not designated as hedges of$103.1 million for the nine months endedSeptember 30, 2021 was comprised of a mark-to-market loss of$88.6 million , representing the change of fair value on our open natural gas derivative contracts, and a$14.5 million loss on net cash settlements of natural gas and oil derivative contracts. Volatility in the commodity futures market is quite high and since we do not apply hedge accounting on our derivative contracts there can be large swings in our reported gain or losses between periods. These commodity derivative losses were recorded as a result of the significant increase in natural gas strip prices as ofSeptember 30, 2021 compared to our hedged prices. The loss on commodity derivatives not designated as hedges of$11.1 million for the three months endedSeptember 30, 2020 was comprised of a$12.7 million mark-to-market loss, representing the change in fair value of our open natural gas and oil derivative contracts, offset by a$1.6 million net gain on cash settlement of natural gas and oil derivative contracts. The loss on commodity derivatives not designated as hedges of$3.6 million for the nine months endedSeptember 30, 2020 was comprised of a$18.5 million mark-to-market loss, representing the change of the fair value of our open natural gas and oil derivative contracts, offset by$14.9 million net gain on cash settlement of natural gas and oil derivative contracts. Income Tax Benefit We recorded no income tax expense or benefit for the three and nine months endedSeptember 30, 2021 and 2020. We maintained a valuation allowance atSeptember 30, 2021 , which resulted in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance after an evaluation of all available evidence led to a conclusion that based upon the more-likely-than-not standard of the accounting literature our deferred tax assets were unrecoverable.
Loss on Early Extinguishment of Debt
The loss on early extinguishment of debt for the nine months endedSeptember 30, 2021 was recorded as a result of the Company exchanging the 2021/2022 Second Lien Notes for the 2023 Second Lien Notes onMarch 9, 2021 . The$0.9 million loss was comprised of the remaining unamortized debt discount of$0.8 million and remaining unamortized debt issuance costs of$0.1 million on the 2021/2022 Second Lien Notes. Adjusted EBITDA Adjusted EBITDA is a supplemental non-United States Generally Accepted Accounting Principle ("US GAAP") financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as earnings before interest expense, income and similar tax, DD&A, share-based compensation expense and impairment of oil and natural gas properties (if any). In calculating Adjusted EBITDA, mark-to-market gains/losses on commodity derivatives not designated as hedges are also excluded. Other excluded items include adjustments resulting from the accounting for operating leases under Accounting Standards Codification ("ASC") Topic 842 in accordance with our 2019 Senior Credit Facility, interest income and any extraordinary non-cash gains or losses. Adjusted EBITDA is not a measure of net income (loss) as determined by US GAAP. Adjusted EBITDA should not be considered an alternative to net income (loss), as defined by US GAAP. The following table presents a reconciliation of net income (loss) to Adjusted EBITDA: Three Months Ended
Nine Months Ended September
September 30, 30,
(In thousands) 2021 2020 2021 2020
Net loss (US GAAP) $ (47,969 ) $ (16,360 ) $ (55,025 ) $ (36,265 )
Interest expense 2,232 1,733 6,255 5,410
Depreciation, depletion and amortization 13,389 10,341 35,671 35,484
Impairment of oil and natural gas
properties - 3,040 - 17,170
Share-based compensation expense
(non-cash) 517 1,035 1,207 3,564
Loss on commodity derivatives not
designated as hedges, not settled 64,871 12,676 88,596 18,534
Loss on early extinguishment of debt - - 935 -
Other items (1) 177 266 246 684
Adjusted EBITDA $ 33,217 $ 12,731 $ 77,885 $ 44,581 (1) Other items included
respectively, from the impact of accounting for operating leases under ASC
Topic 842 as well as interest income for the three and nine months ended
September 30, 2021 and 2020, respectively. Management believes that this non-US GAAP financial measure provides useful information to investors because it is monitored and used by our management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry. 26
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Table of Contents
Liquidity and Capital Resources
Overview Our primary sources of cash during the first nine months of 2021 were cash from operating activities, cash on hand and borrowings under our 2019 Senior Credit Facility (as defined below). We used cash primarily to fund capital expenditures. We currently plan to fund our operations and capital expenditures for the remainder of 2021 through a combination of cash on hand, cash from operating activities and borrowing under our revolving credit facility, although we may from time to time consider the funding alternatives described below. OnMay 14, 2019 , the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the "2019 Credit Agreement") among the Company, the Subsidiary, as borrower (in such capacity, the "Borrower"),Truist Bank , as administrative agent (the "Administrative Agent"), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the "2019 Senior Credit Facility"). The 2019 Senior Credit Facility matures on the earlier of (a)May 14, 2024 or (b)December 2, 2022 , if the 2023 Second Lien Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired byDecember 2, 2022 , which is the date that is 180 days prior to theMay 31, 2023 "Maturity Date" of the 2023 Second Lien Notes. The 2019 Senior Credit Facility provides for a maximum credit amount of$500 million subject to a borrowing base limitation, which was$120.0 million as ofSeptember 30, 2021 and was increased to$150.0 million during the Fall 2021 borrowing base redetermination. The borrowing base is redetermined in March and September of each calendar year, and is subject to additional adjustments from time to time, including, without limitation, for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and the Administrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders in their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. Under the Fifth Amendment to 2019 Credit Agreement entered into onNovember 5, 2021 , the Company is permitted to make restricted payments under the 2019 Credit Agreement so long as (i) no borrowing base deficiency, default or event of default exists or would result therefrom, (ii) after giving pro forma effect to such restricted payment, availability is no less than 20% of the aggregate amount of the available commitments under the 2019 Credit Agreement and (iii) after giving pro forma effect to such restricted payment, the ratio of net funded debt of the Company to EBITDAX shall not be greater than 1.50 to 1.00. The Fifth Amendment to 2019 Credit Agreement also permits the Company to make redemptions of the Second Lien Debt (as defined in the 2019 Credit Agreement) and payments of interest on the 2023 Second Lien Notes so long as each such redemption and interest payment would be permitted as a restricted payment. The Borrower may also request the issuance of letters of credit under the 2019 Credit Agreement in an aggregate amount up to$10 million , which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. OnMarch 9, 2021 , the Company and the Subsidiary entered into a purchase and exchange agreement with certain purchasers (each such purchaser, together with its successors and assigns, a "2023 Second Lien Notes Purchaser") pursuant to which the Company issued to the 2023 Second Lien Notes Purchasers (A)$15.2 million aggregate principal amount of the 2023 Second Lien Notes in exchange for an equal amount of 2021/2022 Second Lien Notes and (B)$15.0 million of the 2023 Second Lien Notes in exchange for cash. Proceeds from the sale of the 2023 Second Lien Notes were used to pay down outstanding borrowings under the 2019 Senior Credit Facility. In connection with the purchase and exchange agreement, we recorded a$0.9 million loss on early extinguishment of debt related to the remaining unamortized debt discount and debt issuance costs from the 2021/2022 Second Lien Notes. The 2023 Second Lien Notes, as set forth in the indenture governing the 2023 Second Lien Notes (the "2023 Second Lien Notes Indenture"), are scheduled to mature onMay 31, 2023 . The 2023 Second Lien Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears onJanuary 15 ,April 15 ,July 15 andOctober 15 of each year. The Company may elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the 2023 Second Lien Notes by increasing the principal amount of the outstanding 2023 Second Lien Notes. The 2023 Second Lien Notes are convertible into the Company's common stock at the conversion rate, which is the sum of the outstanding principal amount of 2023 Second Lien Notes to be converted, including any accrued and unpaid interest, divided by the conversion price, which shall initially be$21.33 , subject to certain adjustments as described in the 2023 Second Lien Notes Indenture. Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the 2023 Second Lien Notes Indenture, (2) cash or (3) a combination of shares of its common stock and cash? however, the Company's ability to redeem the 2023 Second Lien Notes with cash is subject to the terms of the 2019 Credit Agreement. We exited the third quarter of 2021 with$5.5 million cash on hand and$90.4 million of outstanding borrowings with$29.6 million of availability under the 2019 Senior Credit Facility borrowing base of$120.0 million in effect as ofSeptember 30, 2021 . Outlook
We plan to focus all of our capital on drilling and development of our
Haynesville Shale Trend natural gas properties in
We believe the results of the capital investments we made in prior years and the
nine months of 2021 will generate additional cash flows and additional value
that will allow us to continue our capital development in the future and raise
capital as needed.
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We continuously monitor our leverage position and coordinate our capital program with our expected cash flows and repayment of our projected debt. We will continue to evaluate funding alternatives as needed.
Alternatives available to us include:
• availability under the 2019 Senior Credit Facility;
• issuance of debt securities;
• joint ventures in our TMS and/or Haynesville Shale Trend acreage;
• sale of non-core assets; and
• issuance of equity securities if favorable conditions exist.
In addition, to support future cash flows and protect against a sharp drop in
commodity prices, we enter into strategic derivative positions as reflected
in Note 8-"Commodity Derivative Activities" and Note 11-"Subsequent Events" in
the Notes to Consolidated Financial Statements under Part I, Item 1 of this
Quarterly Report on Form 10-Q.
We have had an on-going company-wide cost reduction program eliminating outside
services that are not core to our business, which we continue to focus on, as
well as a reduction in headcount year over year. As a result of the steps we
have taken to enhance our liquidity in addition to the current natural gas
pricing environment, we anticipate our cash on hand, cash from operations and
our available borrowing capacity under our 2019 Senior Credit Facility will be
sufficient to meet our investing, financing, and working capital requirements
over the next year.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in
thousands):
Three Months Ended Nine Months Ended September
September 30, 30,
2021 2020 2021 2020
Cash flow statement information:
Net cash:
Provided by operating activities $ 29,935 $ 13,512 $ 66,604 $ 44,592
Used in investing activities (25,045 ) (14,816 ) (71,065 ) (48,012 )
Provided by (used in) financing
activities (161 ) 991 8,612 3,219
Increase (decrease) in cash and cash
equivalents $ 4,729 $ (313 ) $ 4,151 $ (201 )
Operating activities: Production from our wells, the price of oil and natural
gas and operating costs represent the main drivers behind our cash flow from
operations for the three and nine months ended September 30, 2021 and 2020.
Changes in working capital and net cash settlements related to our derivative
contracts also impact cash flows. Net cash provided by operating activities for
the three months ended September 30, 2021 was $29.9 million including operating
cash flows before negative working capital changes of $32.3 million including
net cash payments of $12.5 million in settlement of derivative contracts. Net
cash provided by operating activities for the nine months ended September 30,
2021 was $66.6 million including operating cash flows before negative working
capital changes of $75.4 million including net cash payments of $14.5 million in
settlement of derivative contracts. The changes in cash provided by operating
activities compared to prior year was primarily attributable to changes in oil
and natural gas revenues driven by increased realized prices and increased
production, offset by the use of cash based on timing of working capital
expenditures.
Investing activities: Net cash used in investing activities, which represents
our cash expended for capital projects, was $25.0 million and $71.1 million for
the three and nine months ended September 30, 2021 , respectively. We recorded
$27.9 million in capital expenditures during the three months ended September
30, 2021 . The difference in capital expenditures and cash expended on capital
projects for the three months ended September 30, 2021 was primarily attributed
to a net capital accrual increase of $2.3 million and capitalization of
$0.4 million of asset retirement and non-cash internal costs. We recorded $77.0
million in capital expenditures during the nine months ended September 30,
2021 . The difference in capital expenditures and cash expended on capital
projects for the nine months ended September 30, 2021 was attributed to a net
capital accrual increase of $4.6 million and, utilization of $0.6 million in
cash calls and the capitalization of $0.7 million of asset retirement and
non-cash internal costs. During the nine months ended September 30, 2021 , we
conducted drilling and completion operations on 24 gross (10.5 net) wells
bringing 16 gross (8.1 net) wells on production with 8 gross (2.3 net) wells
remaining in the drilling and completion process at September 30, 2021 .
Financing activities: Net cash provided by (used in) financing activities for
the three and nine months ended September 30, 2021 and 2020 primarily reflected
net borrowings under our 2019 Senior Credit Facility and proceeds from the
issuance of the 2023 Second Lien Notes, offset by debt issuance costs paid in
connection with issuance of the 2023 Second Lien Notes and cash paid for
treasury shares in connection with restricted stock vesting.
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Debt consisted of the following balances as of the dates indicated (in
thousands):
September 30, 2021 December 31, 2020
Carrying Carrying
Principal Amount Principal Amount
2019 Senior Credit Facility (1) $ 90,400 $ 90,400 $ 96,400 $ 96,400
2021/2022 Second Lien Notes (2) - - 14,811 13,759
2023 Second Lien Notes (3) 32,535 31,349 - -
Total debt $ 122,935 $ 121,749 $ 111,211 $ 110,159 (1) The carrying amount for the 2019 Senior Credit Facility represents fair value as its variable interest rate approximates market rates.
(2) The debt discount was being amortized using the effective interest rate
method based upon a maturity date of
(3) The debt discount is being amortized using the effective interest rate method based upon a maturity date ofMay 31, 2023 . The principal includes$2.3 million of paid in-kind interest as ofSeptember 30, 2021 . The carrying value includes$0.9 million of unamortized debt discount and$0.3 million of unamortized issuance cost as ofSeptember 30, 2021 .
For additional information on our financing activities, see Note 4-"Debt" in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.
Off-Balance Sheet Arrangements
We do not currently have any off-balance sheet arrangements for any purpose.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements, which were prepared in accordance with US GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We believe that certain accounting policies affect the more significant judgments and estimates used in the preparation of our consolidated financial statements. Our Annual Report on Form 10-K for the year endedDecember 31, 2020 includes a discussion of our critical accounting policies, and there have been no material changes to such policies during the nine months endedSeptember 30, 2021 . 29
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