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, 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:
• 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;
• production;
• 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;
• the ability of the
set and maintain production levels and pricing;
• public health crises, such as the COVID-19 pandemic, which has adversely
impacted the demand for and price of crude oil and the global economy;
• 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
report and Part I, "Item 1A. Risk Factors" in our Annual Report on Form 10-K for
the year ended December 31, 2019 .
21--------------------------------------------------------------------------------
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. We strive 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. 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, when establishing our capital expenditure budget. We place primary emphasis on our operating cash flow in managing our business. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of unrealized hedging gains (losses), non-cash general and administrative expenses and impairments. 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. Such pricing factors are largely beyond our control; however, we employ commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow. The Coronavirus Disease 2019 ("COVID-19") pandemic and related economic repercussions have created significant volatility, uncertainty and turmoil in the oil and gas industry. Throughout the first nine months of 2020, the effect of COVID-19 has lowered the demand for oil and natural gas which has resulted in an oversupply of crude oil with significant downward pressure on oil and natural gas prices. West Texas Intermediate crude oil closed at$21 per barrel onMarch 31, 2020 and generally remained at that level or lower throughMay 2020 . In the third quarter of 2020, we experienced a gradual increase in oil and natural gas prices although not enough to alleviate the oversupply caused by lack of demand caused by COVID-19. The ultimate magnitude and duration of the COVID-19 pandemic, resulting governmental restrictions placing limitations on the mobility and ability to work of the worldwide population and the related impact on crude oil prices and theU.S. and global economy and capital markets remains uncertain. 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 this downturn 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 have reduced our capital expenditures planned for 2020 thereby conserving capital. We have initiated a company-wide cost reduction program eliminating outside services that are not core to our business. Additionally, we have substantial volumes of our production favorably hedged through the first quarter of 2022 and can further reduce our capital expenditures if necessary. 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 2021.
We remain committed to the following priorities while navigating through the COVID-19 pandemic:
• Ensure the health and safety of our employees and the contractors which
provide services to us;
• Continue 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
• Ensure we emerge from the COVID-19 pandemic and current oil and natural gas
price environment in as strong of a position as possible as we continue to
move forward with our long-term strategies.
While the potential still exists for the COVID-19 pandemic to adversely affect
our operations or employees' health, 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 most employees working remotely where possible in
compliance with governmental orders and CDC recommendations.
Primary Operating Areas
Haynesville Shale Trend
Our relatively low risk development acreage in this trend is primarily centered
in Caddo , DeSoto and Red River parishes, Louisiana and Angelina and Nacogdoches
counties, Texas . We have acquired or farmed-in leases totaling approximately
42,000 gross (24,000 net) acres as of September 30, 2020 in the Haynesville
Shale Trend. We completed and produced 8 gross (3.0 net) new wells in the third
quarter of 2020 and had 4 gross (0.6 net) wells in the drilling or
completions phase as of September 30, 2020 . Our net production volumes from our
Haynesville Shale Trend wells represented approximately 96% of our total
equivalent production on a Mcfe basis and substantially all of our natural gas
production for the third quarter of 2020. 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 2020 drilling efforts.
Tuscaloosa Marine Shale Trend
We have acquired approximately 48,000 gross (33,000 net) lease acres in the TMS as ofSeptember 30, 2020 which is 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 2% of our total equivalent production on a Mcfe basis and 98% of our total oil production for the third quarter of 2020. Despite no capital expenditures, we are seeking to maintain production through strategic expense workover operations in the TMS. 22
--------------------------------------------------------------------------------
Table of Contents Eagle Ford Shale Trend We have retained approximately 4,300 net acres of undeveloped leasehold in the Eagle Ford Shale Trend inFrio County, Texas as ofSeptember 30, 2020 , which is prospective for future development or sale. Results of Operations 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. Please see "Revenues from Operations", "Gain (Loss) on Commodity Derivatives Not Designated as Hedges" and "Impairment Expense" below for further discussion. The item that had the most material financial effect on our net income of$2.0 million for the three months endedSeptember 30, 2019 was a$3.8 million gain on derivatives not designated as hedges. The majority of the gain was attributable to settlement of our natural gas derivative positions at prices lower than our fixed contract prices. The items that had the most material financial effect on our net income of$14.2 million for the nine months endedSeptember 30, 2019 , in addition to derivative settlement and mark-to-market gains, were oil and gas revenues, transportation and processing expense and depletion, depreciation and amortization expense. All these items increased compared to the nine months endedSeptember 30, 2018 , which is primarily attributable to production volume increases. The following table reflects our summary operating information for the periods presented (in thousands, except for price and volume data). Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results. Revenues from Operations Three Months Ended September 30, Nine Months Ended September 30, (In thousands, except for price and average daily production data) 2020 2019 Variance 2020 2019 Variance
Revenues:
Natural gas$ 20,167 $ 24,684 $ (4,517 ) (18
)%
1,296 2,477 (1,181 ) (48 )% 4,547 8,207 (3,660 ) (45 )% Natural gas, oil and condensate
21,463 27,161 (5,698 ) (21 )% 64,917 88,193 (23,276 ) (26 )% Net Production: Natural gas (Mmcf)
11,346 12,257 (911 ) (7 )% 35,937 33,622 2,315 7 %
Oil and condensate
(MBbls) 33 42 (9 ) (21 )% 107 134 (27 ) (20 )%
Total (Mmcfe) 11,543 12,506 (963 ) (8 )% 36,576 34,425 2,151 6 %
Average daily
production (Mcfe/d) 125,462 135,936 (10,474 ) (8 )% 133,487 126,097 7,390 6 %
Average realized sales
price per unit:
Natural gas (per Mcf) $ 1.78 $ 2.01 $ (0.23 ) (11 )% $ 1.68 $ 2.38 $ (0.70 ) (29 )%
Natural gas (per Mcf)
including the effect of
realized gains/losses
on derivatives $ 1.89 $ 2.51 $ (0.62 ) (25 )% $ 2.06 $ 2.58 $ (0.52 ) (20 )%
Oil and condensate (per
Bbl) $ 39.63 $ 59.67 $ (20.04 ) (34 )% $ 42.76 $ 61.40 $ (18.64 ) (30 )%
Oil and condensate (per
Bbl) including the
effect of realized
gains/losses on
derivatives $ 49.90 $ 56.09 $ (6.19 ) (11 )% $ 55.06 $ 57.52 $ (2.46 ) (4 )%
Average realized price
(per Mcfe) $ 1.86 $ 2.17 $ (0.31 ) (14 )% $ 1.77 $ 2.56 $ (0.79 ) (31 )%
Natural gas, oil and condensate revenues decreased by $5.7 million and $23.3
million , respectively, for the three and nine months ended September 30,
2020 compared to the same periods in 2019. For the three months ended September
30, 2020 as compared to the prior year period, the decrease was primarily driven
by lower realized oil and natural gas prices as well as decreased production
volumes as a result of normal well production decline and the timing of new
wells brought online in the later part of the quarter. For the nine months ended
September 30, 2020 as compared to the prior year, the decrease was primarily
driven by lower realized oil and natural gas prices, partially offset by
increased natural gas production volumes as a result of our capital expenditure
program.
23--------------------------------------------------------------------------------
Table of Contents Operating Expenses As described below, total operating expenses decreased$1.9 million and increased$13.8 million for the three and nine months endedSeptember 30, 2020 , respectively, compared to the same periods in 2019. The decrease in total operating expenses for the three months endedSeptember 30, 2020 was primarily due to decreased transportation, general and administrative and depreciation, depletion and amortization expense. The increase in total operating expenses for the nine months endedSeptember 30, 2020 was primarily due to impairment expense as well as increased LOE and production and other taxes, offset by lower transportation costs and general and administrative expense. Three Months Ended September 30, Nine Months Ended September 30, Operating Expenses (in thousands) 2020 2019 Variance 2020 2019 Variance Lease operating expenses$ 2,831 $ 2,589 $ 242 9 %$ 9,384 $ 8,902 $ 482 5 % Production and other taxes 591 623 (32 ) (5 )% 2,361 1,878 483 26 % Transportation and processing 4,336 5,107 (771 ) (15 )% 14,586 15,562 (976 ) (6 )% Operating Expenses per Mcfe Lease operating expenses$ 0.25 $ 0.21 $ 0.04 19 %$ 0.26 $ 0.26 $ - 0 % Production and other taxes$ 0.05 $ 0.05 $ - 0 %$ 0.06 $ 0.05 $ 0.01 20 % Transportation and processing$ 0.38 $ 0.41 $ (0.03 ) (7 )%$ 0.41 $ 0.45 $ (0.04 ) (9 )% Lease Operating Expense Lease operating expense ("LOE") increased$0.2 million and$0.5 million for the three and nine months endedSeptember 30, 2020 , respectively, compared to the same periods in 2019. The increase in LOE is primarily attributed to workover expense. Per unit operating cost was$0.25 and$0.26 per Mcfe for the three and nine months endedSeptember 30, 2020 of which$0.03 per Mcfe was attributed to the$0.3 million in workover expense incurred in the three months and$0.04 per Mcfe was attributed to the$1.3 million incurred in the nine months endedSeptember 30, 2020 . We are maintaining production levels in 2020 through our selective workover projects. Production and Other Taxes Production and other taxes includes severance and ad valorem taxes. Severance taxes for the three and nine months endedSeptember 30, 2020 were$0.4 million and$1.5 million , respectively, and ad valorem taxes were$0.2 million and$0.9 million for the three and nine months endedSeptember 30, 2020 , respectively. Severance taxes remained the same for the three months endedSeptember 30, 2020 and increased$0.4 million for the nine months endedSeptember 30, 2020 , as compared with the same periods in 2019 The current quarter severance tax expense reflects the reduction of the severance tax rate that was effective onJuly 1, 2020 while the current year to date expense reflects the expiration of tax exemptions on certain wells. OnJuly 1, 2020 , the severance tax rate on natural gas production was reduced to$0.0934 per Mcf from the$0.125 per Mcf rate that was effective onJuly 1, 2019 . TheState of Louisiana has enacted an exemption from severance tax on oil and 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 Haynesville Shale Trend wells inNorthwest Louisiana are benefiting from this exemption. Ad valorem tax remained relatively flat for the three months endedSeptember 30, 2020 and increased$0.1 million for the nine months endedSeptember 30, 2020 , as compared with the same periods in 2019. The slight increase in the current year to date period is due to our increased well count. 24
--------------------------------------------------------------------------------
Table of Contents
Transportation and Processing
Transportation and processing expense for the three and nine months endedSeptember 30, 2020 decreased$0.8 million and$1.0 million , respectively, compared to the same periods in 2019, despite an increase in production volumes for the year. We have increased production from our operatedHaynesville Shale Trend wells for which we have contracted more favorable rates than those of our non-operated properties. Our natural gas volumes from operated wells generally carry less transportation cost than those from wells we do not operate. For the same reason, our per unit transportation cost per Mcfe cost decreased in both the three and nine months endedSeptember 30 , 2020,compared to the same periods in 2019. Three Months Ended September 30, Nine Months Ended September 30, Operating Expenses (in thousands): 2020 2019 Variance 2020 2019 Variance Depreciation, depletion and amortization$ 10,341 $ 13,205 $ (2,864 ) (22 )%
3,891 5,196 (1,305 ) (25 )% 13,327 15,442 (2,115 ) (14 )% Impairment of oil and natural gas properties 3,040
- 3,040 100 % 17,170 - 17,170 100 %
Other (11 ) 228 (239 ) (105 )% (13 ) 179 (192 ) (107 )%
Operating Expenses per
Mcfe
Depreciation,
depletion and
amortization $ 0.90 $ 1.06 $ (0.16 ) (15 )% $ 0.97 $ 1.06 $ (0.09 ) (8 )%
General and
administrative $ 0.34 $ 0.42 $ (0.08 ) (19 )% $ 0.47 $ -$ 0.47 100 % Other $ -$ 0.02 $ (0.02 ) (100 )% $ -$ 0.01 $ (0.01 ) (100 )%
Depreciation, Depletion and Amortization ("DD&A") Expense
DD&A expense is calculated under the Full Cost Method using the units of production method. DD&A expense for the three months endedSeptember 30, 2020 decreased$2.9 million , and DD&A expense for the nine months endedSeptember 30, 2020 decreased$1.1 million compared to the same periods in 2019.These decreases were due to using a lower DD&A rate in 2020 offset by the effect of increased production volumes for the year. We calculate our DD&A rates at least semi-annually in connection with the preparation of our reserve report onDecember 31st andJune 30th which is used for that ending period. TheJune 30, 2020 and subsequently theSeptember 30, 2020 calculation recognized the decreases in drilling and completion cost that the industry is currently experiencing which has lowered the DD&A rate. Impairment Expense The Full Cost Method requires that we perform a quarterly Ceiling Test. The Ceiling Test performed as ofSeptember 30, 2020 indicated that the net book value of our proved oil and natural gas properties exceeded the estimated discounted future net cash flows resulting in a$3.0 million impairment of oil and natural gas properties for the three months endedSeptember 30, 2020 , and$17.2 million for the nine months endedSeptember 30, 2020 , due to the low commodity price environment experienced during 2020 which brought the trailing 12-month average price to$1.97 per mcf of natural gas. Commodity prices have the greatest effect on the determination of an impairment, among other factors. Recently, natural gas future prices are trending upward; however, any commodity price deterioration from current levels may indicate an impairment of our oil and natural gas properties in the future. Please refer to Note 1-"Description of Business and Significant Accounting Policies-Full Cost Ceiling Test" in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q for additional details.
General and Administrative ("G&A") Expense
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. G&A expense decreased for the three and nine months endedSeptember 30, 2020 by$1.3 million and$2.1 million , respectively, compared to the same periods in 2019, primarily due to reduced stock compensation expense of$0.6 million and$1.2 million , respectively. Additional reductions occurred in accrued employee performance bonus expense and employee related expenses resulting from employee retirements during 2020. The Company recorded$5.2 million and$15.4 million , respectively, in G&A expense for the three and nine months endedSeptember 30, 2019 . G&A expense for the three and nine months endedSeptember 30, 2019 included non-cash expenses of$1.6 million and$4.7 million , respectively, for share-based compensation. Other Income (Expense) Three Months Ended September 30, Nine Months Ended September 30, Other income (expense) (in thousands): 2020 2019 Variance 2020 2019 Variance Interest expense$ (1,733 ) $ (1,981 ) $ (248 ) (13
)%
5 - 5 100 % 147 24 123 513 %
Gain (loss) on commodity
derivatives not
designated as hedges (11,079 ) 3,752 (14,831 ) 395 % (3,629 ) 15,397 (19,026 ) 124 %
Loss on early
extinguishment of debt - - - 0 % - (1,846 ) 1,846 (100 )%
Average funded
borrowings adjusted fordebt discount$ 107,268 $ 95,761 $ 11,507 12 %$ 104,925 $ 92,641 $ 12,284 13 % Average funded borrowings$ 110,505 $ 99,598 $ 10,907 11 %$ 108,323 $ 96,323 $ 12,000 12 % Interest Expense The Company's 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 Company's 13.50% Convertible Second Lien Senior Secured Notes due 2022 (the "New 2L 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 . Interest expense for the three and nine months endedSeptember 30, 2019 reflected interest payable in cash of$1.2 million and$2.7 million , respectively, incurred on the 2017 Senior Credit Facility and 2019 Senior Credit Facility and non-cash interest of$0.7 million and$6.3 million , respectively, incurred primarily on the Company's Convertible Second Lien Notes and New 2L Notes, which included$0.4 million and$3.6 million , respectively, of paid in-kind interest and$0.3 million and$2.8 million , respectively, of debt discount and debt issuance cost amortization. Interest expense decreased$0.2 million and$3.6 million , respectively, for the three and nine months endedSeptember 30, 2020 , compared to the same periods in 2019, having paid off in 2019 the higher interest bearing Convertible Second Lien Notes with borrowings from the 2019 Senior Credit Facility which carry a lower interest rate. 25
--------------------------------------------------------------------------------
Table of Contents
Gain (Loss) on Commodity Derivatives Not Designated as Hedges
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 derivatives, 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 Volatility in the commodity futures market is quite high and since we do not apply hedge accounting on our derivatives contracts there can be large swings in our reported gains or losses between periods. Going forward, any increase in natural gas futures prices would result in recording of losses in future periods. The gain on commodity derivatives not designated as hedges for the three months endedSeptember 30, 2019 was comprised of$5.9 million gain on cash settlements during the period offset by a mark-to-market loss of$2.2 million , representing the change of the fair value of our natural gas derivative contracts. The gain on commodity derivatives not designated as hedges for the nine months endedSeptember 30, 2019 was comprised of a mark-to-market gain of$9.3 million , representing the change of the fair value of our natural gas derivative contracts, and a$6.1 million gain on net cash settlements during the period. Income Tax Benefit We recorded no income tax expense or benefit for the three and nine months endedSeptember 30, 2020 or 2019. We maintained a valuation allowance atSeptember 30, 2020 , 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 (including commodity prices and our recent history of tax net operating losses ("NOLs") in 2019 and prior years) led to a conclusion that based upon the more-likely-than-not standard of the accounting literature our deferred tax assets were unrecoverable. The valuation allowance was$74.2 million as ofDecember 31, 2019 , which resulted in a net non-current deferred tax asset of$0.4 million appearing on our statement of financial position at that time. The net$0.4 million deferred tax asset related to alternative minimum tax ("AMT") credits and accrued interest which were refundable to the Company was reclassed to a current receivable as ofJune 30, 2020 , and such funds were subsequently received in the third quarter of 2020. The valuation allowance has no impact on our NOL position for tax purposes, and if we generate taxable income in future periods, we may be able to use our NOLs to offset taxable income at that time subject to any applicable tax limitations on the NOLs. Considering the Company's taxable income forecasts, our assessment of the realization of our deferred tax assets has not changed, and we continue to maintain a full valuation allowance for our net deferred tax assets as ofSeptember 30, 2020 . 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, gains/losses on reorganization and 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") 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 the non-US GAAP measure of Adjusted EBITDA to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP:
Three Months Ended September 30, Nine Months Ended September 30,
(In thousands) 2020 2019 2020 2019
Net income (loss) (US GAAP) $ (16,360 ) $ 1,988 $ (36,265 ) $ 14,215
Interest expense 1,733 1,981 5,410 9,036
Depreciation, depletion and amortization 10,341 13,205 35,484 36,550
Impairment of oil and natural gas
properties 3,040 - 17,170 -
Share-based compensation expense
(non-cash) 1,035 1,617 3,564 4,765
Loss (gain) on commodity derivatives not
designated as hedges, not settled 12,676 2,170 18,534 (9,262 )
Loss on early extinguishment of debt - - - 1,846
Other items (1) 266 297 684 855
Adjusted EBITDA $ 12,731 $ 21,258 $ 44,581 $ 58,005 (1) Other items included
leases under ASC 842 as well as interest income for the three and nine months
ended September 30, 2020 and 2019, 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--------------------------------------------------------------------------------
Table of Contents
Liquidity and Capital Resources
Overview Our primary sources of cash during the first nine months of 2020 were cash on hand and cash from operating activities. We used cash primarily to fund capital expenditures. We currently plan to fund our operations and capital expenditures for the remainder of 2020 through a combination of cash on hand, cash from operating activities and borrowings 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 (formerlySunTrust 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 amended, restated and refinanced the obligations under our 2017 Credit Agreement. The 2019 Senior Credit Facility matures (a)May 14, 2024 or (b)December 3, 2021 , if the New 2L Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired byDecember 3, 2021 , which is the date that is 180 days prior to theMay 31, 2022 "Maturity Date" of the New 2L Notes. The 2019 Senior Credit Facility provides for a maximum credit amount of$500 million subject to a borrowing base limitation, which was originally$115 million . The borrowing base was increased to$125 million inAugust 2019 and was decreased to$120 million inMay 2020 , which was reaffirmed in the fall 2020 redetermination. The borrowing base is scheduled to be redetermined in March and September of each calendar year, and is subject to additional adjustments from time to time, including 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 at their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. 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. OnMay 14, 2019 , the Company and the Subsidiary entered into a purchase agreement with certain funds and accounts managed byFranklin Advisers, Inc. , as investment manager (each such fund or account, together with its successors and assigns, a "New 2L Notes Purchaser") pursuant to which the Company issued to the New 2L Notes Purchasers (the "New 2L Notes Offering")$12.0 million aggregate principal amount of the Company's 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the "New 2L Notes"). The closing of the New 2L Notes Offering occurred onMay 31, 2019 . Proceeds from the sale of the New 2L Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility. Holders of the New 2L Notes have a second priority lien on all assets of the Company. The New 2L Notes, as set forth in the indenture governing the New 2L Notes were scheduled to mature onMay 31, 2021 . InMay 2020 , the maturity date of the New 2L Notes was extended toMay 31, 2022 . The New 2L 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 New 2L Notes by increasing the principal amount of the outstanding New 2L Notes. We exited the third quarter of 2020 with$1.3 million cash on hand and$96.4 million of outstanding borrowings with$23.6 million of availability under the 2019 Senior Credit Facility borrowing base of$120.0 million in effect as ofSeptember 30, 2020 . Due to the timing of payment of our capital expenditures, we reflected a working capital deficit of$34.3 million as ofSeptember 30, 2020 . Subsequently, our working capital deficit was not covered by availability under the 2019 Senior Credit Facility, and we were therefore not in compliance with our current ratio under the 2019 Senior Credit Facility. OnOctober 30, 2020 , we entered into a Third Amendment to Credit Agreement with the Subsidiary,Truist Bank , as administrative agent, and the lenders party thereto, pursuant to which, among other things, the lenders agreed to waive the default caused by our failure to comply with the current ratio financial covenant under the 2019 Senior Credit Facility as of the last day of the fiscal quarter endedSeptember 30, 2020 . To the extent we continue to operate with a working capital deficit, we expect such deficit to be offset by liquidity available under our 2019 Senior Credit Facility. Compliance with our covenants under the 2019 Senior Credit Facility and New 2L Notes is primarily dependent upon our capital spending program. We have taken advantage of the improving natural gas prices by completing wells in the third quarter which were drilled in prior quarters. Our financial forecast indicates we will be in compliance with all our bank covenants through 2021. Outlook Our capital expenditures for the remainder of 2020 and 2021 are dependent upon commodity prices. We have the flexibility to move forward with or delay capital projects based on the upward or downward movement of commodity prices. We plan to continue to focus all of our capital on drilling and development of our Haynesville Shale Trend natural gas properties inNorth Louisiana . We believe the results of the capital investments we made in 2019 and thus far in 2020 will generate sufficient cash flows and coupled with the availability under our 2019 Senior Credit Facility will allow us to execute our operational plans through 2021. That value that is created will allow us to raise capital to continue our capital development in the future. 27
--------------------------------------------------------------------------------
Table of Contents
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. We have supported our cash flows with derivative contracts that covered approximately 53% of our natural gas sales volumes for the first nine months of 2020 and 59% of our oil volumes for the first nine months of 2020. We have approximately 50% of our forecasted natural gas production hedged through the first quarter of 2022 at a weighted average price of$2.53 per Mcf. We have approximately 52% of our forecasted oil production hedged through the first quarter of 2021 at a weighted average price of$57.05 per barrel. For additional information on our derivative instruments see Note 8-"Commodity Derivative Activities" in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q. To mitigate the effects of the downturn in commodity prices experienced during 2020 due to the effects of COVID-19, we reduced our capital expenditures for 2020 thereby conserving capital. We also initiated a company-wide cost reduction program eliminating outside services that are not core to our business. Additionally, we have substantial volumes of our production favorably hedged through the first quarter of 2022 and can further adjust our capital expenditures based upon commodity prices, if necessary. As a result of the steps we have taken to enhance our liquidity, we anticipate our cash on hand, cash from operations and our available borrowing capacity under our 2019 Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements into 2021. Cash Flows The following table summarizes our cash flows for the periods indicated (in thousands): Three Months Ended Nine Months Ended September September 30, 30, 2020 2019 2020 2019 Cash flow statement information: Net cash: Provided by operating activities$ 13,512 $ 15,594 $ 44,592 $ 56,847 Used in investing activities (14,816 ) (19,083 ) (48,012 ) (72,865 ) Provided by financing activities 991 2,980 3,219 13,110
Decrease in cash and cash equivalents
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 endedSeptember 30, 2020 and 2019. 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 endedSeptember 30, 2020 was$13.5 million including operating cash flows before positive working capital changes of$11.8 million , including net cash receipts of$1.6 million in settlement of derivative contracts. Net cash provided by operating activities for the nine months endedSeptember 30, 2020 was$44.6 million including operating cash flows before positive working capital changes of$41.7 million , including net cash receipts of$14.9 million in settlement of derivative contracts. The decrease in cash provided by operating activities for the three and nine months endedSeptember 30, 2020 compared to the same periods in 2019 was primarily attributable to decreases in oil and natural gas revenues driven by decreased realized prices. Investing activities: Net cash used in investing activities was$14.8 million and$48.0 million for the three and nine months endedSeptember 30, 2020 , respectively, which reflected cash expended on capital projects. We recorded$16.9 million in capital expenditures during the three months endedSeptember 30, 2020 . The difference in capital expenditures and cash expended on capital projects for the three months endedSeptember 30, 2020 was attributed to a net capital accrual increase of$2.7 million and$0.1 million of asset retirement and non-cash internal costs, offset by$0.7 million in cash calls paid on our non-operated wells. During the three months endedSeptember 30, 2020 , we conducted drilling and completion operations and brought onto production 8 gross (3.0 net) wells. We recorded$45.5 million in capital expenditures during the nine months endedSeptember 30, 2020 . The difference in capital expenditures and cash expended on capital projects for the nine months endedSeptember 30, 2020 was attributed to a net capital accrual decrease of$2.4 million and$0.7 million in paid cash calls on non-operated wells, offset by capitalization of$0.6 million of asset retirement and non-cash internal costs. Though we have reduced our drilling and completion activities, we are still paying for capital costs incurred and recorded in prior periods. During the nine months endedSeptember 30, 2020 , we conducted drilling and completion operations on 20 gross (6.1 net) wells bringing 16 gross (5.5 net) wells on production with 6.0 gross (2.4 net) wells remaining in the drilling and completion process atSeptember 30, 2020 . Financing activities: Net cash provided by financing activities for the three and nine months endedSeptember 30, 2020 reflected$1.0 million and$3.5 million of net borrowings under our 2019 Senior Credit Facility, respectively, offset by$0.3 million for the purchase of shares withheld from employee stock award vestings for the payment of taxes in the nine month period endedSeptember 30, 2020 . 28
--------------------------------------------------------------------------------
Table of Contents
Debt consisted of the following balances as of the dates indicated (in
thousands):
September 30, 2020 December 31, 2019
Carrying
Principal Amount Principal Carrying Amount
2019 Senior Credit Facility (1) $ 96,400 $ 96,400 $ 92,900 $ 92,900
New 2L Notes (2) 14,327 13,129 12,969 11,535
Total debt $ 110,727 $ 109,529 $ 105,869 $ 104,435
(1) The carrying amount for the 2019 Senior Credit Facility represents fair value as it was fully secured.
(2) The debt discount is being amortized using the effective interest rate method based upon a maturity date ofMay 31, 2022 . The principal includes$2.3 million and$1.0 million of paid in-kind interest as ofSeptember 30, 2020 andDecember 31, 2019 , respectively. The carrying value includes$1.0 million and$1.1 million of unamortized debt discount and$0.2 million and$0.3 million of unamortized issuance cost as ofSeptember 30, 2020 andDecember 31, 2019 , respectively.
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, 2019 includes a discussion of our critical accounting policies and there have been no material changes to such policies during the three and nine months endedSeptember 30, 2020 . 29
--------------------------------------------------------------------------------
Table of Contents
© Edgar Online, source
