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Laredo Petroleum Announces Third-Quarter 2020 Financial and Operating Results


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Increases Oil and Total Production Guidance for Fourth-Quarter and Full-Year 2020

Source: Laredo Petroleum, Inc.

TULSA, OK, Nov. 04, 2020 (GLOBE NEWSWIRE) — Laredo Petroleum, Inc. (NYSE: LPI) (“Laredo” or “the Company”) today announced its third-quarter 2020 results. For the third quarter of 2020, the Company reported a net loss attributable to common stockholders of $237.4 million, or $20.32 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the third quarter of 2020 was $47.0 million, or $4.02 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the third quarter of 2020 was $137.3 million.

Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures, including a calculation of Adjusted EBITDA, Adjusted Net Income and Free Cash Flow.

Third-Quarter 2020 Highlights

  • Generated Free Cash Flow, a non-GAAP financial measure, of $71 million and reduced net debt, a non-GAAP financial measure, by $64 million during third-quarter 2020
  • Received $58.2 million from settlements of matured/terminated commodity derivatives, resulting in an average hedged sales price of $22.76 per barrel of oil equivalent (“BOE”), a 39% increase versus an average unhedged sales price of $16.39 per BOE in the same period
  • Added 6,800 barrels of oil per day (“BOPD”) of 2021 oil hedges at a weighted-average swap price of $45.55 Brent, increasing 2021 oil hedges to 22,150 BOPD, equivalent to 80% of anticipated 2021 oil production
  • Lowered lease operating expenses (“LOE”) to $2.45 per BOE, an 18% decrease from third-quarter 2019
  • Reduced general and administrative expenses (“G&A”), excluding long-term incentive plan (“LTIP”), to $1.16 per BOE, a 21% decrease from third-quarter 2019
  • Produced an average of 25,120 BOPD and total production of 87,857 BOE per day, a decrease of 10% and an increase of 7%, respectively, from third-quarter 2019, while reducing drilling and completions capital expenditures by 54% during the same period

“Since launching our revised strategy a year ago, the Laredo team has delivered on our core objectives of operational excellence, financial risk management and inventory expansion, and this quarter was no exception,” commented Jason Pigott, President and Chief Executive Officer. “We began completions operations in Howard County and did not miss a beat operationally, continuing our exemplary run of efficiency gains and proving we can maintain our low drilling and completions costs in a new area. We generated $71 million in Free Cash Flow, supported by our robust hedge position, enabling us to reduce debt and increase liquidity, and added more hedges in 2021 to further protect future cash flows. We have also increased fourth-quarter and full-year 2020 oil and total production guidance while maintaining our full-year capital expenditure guidance as our base production continued to outperform expectations during the third quarter.”

“In October, we closed on a bolt-on transaction in Howard County, lengthening our runway of higher-margin development opportunities, and our bank group reaffirmed our $725 million borrowing base,” continued Mr. Pigott. “We have built tremendous momentum in our business that we expect to carry into 2021 as we bring on our first package of wells in Howard County, execute a continuous development plan within cash flow and focus on further expanding our inventory of high-return locations in Howard County.”

Operations Summary

During third-quarter 2020, Laredo resumed completions operations, deploying a completions crew in Howard County. The crew is currently operating on a 15-well package that is expected to be fully online in early December. To date, the transition of the Company’s operations to Howard County has exceeded expectations as both drilling and completions efficiencies have set Company records and well costs are tracking to initial estimates of $550 per foot.

Laredo produced 87,857 BOE per day in the third quarter of 2020, including oil production of 25,120 BOPD, with both figures exceeding the midpoint of guidance. Oil production results were driven by continued improvement of the Company’s first package of wells on its western Glasscock County acreage, acquired in December 2019.

The Company is currently operating one drilling rig and one completions crew, both located in Howard County, and expects to complete 15 wells during fourth-quarter 2020.

Expenses

Laredo continues to stringently manage cash expenses, maintaining a peer-leading cost structure. During third-quarter 2020, the Company reduced combined unit LOE and cash G&A expenses to $3.61 per BOE, a reduction of 19% from third-quarter 2019.

Laredo has transitioned to selling almost all of its production at Gulf Coast pricing, which the Company believes provides a long-term pricing advantage versus the Midland market. As such, transportation and marketing expenses, reflecting costs associated with transporting the Company’s produced oil to the US Gulf Coast and expected deficiency payments related to minimum transportation volume commitments, increased to $1.63 per BOE in third-quarter 2020 compared to $0.74 per BOE in third-quarter 2019 as more produced oil was transported to the US Gulf Coast and the Company expensed anticipated future deficiency payments.

Third-Quarter and Full-Year 2020 Costs Incurred

During the third quarter of 2020, total costs incurred were $43 million, comprised of $31 million in drilling and completions activities, $2 million in land, exploration and data related costs, $4 million in infrastructure, including Laredo Midstream Services investments, and $6 million in other capitalized costs.

Through the first nine months of 2020, excluding non-budgeted acquisitions, total costs incurred were $276 million. The Company expects total costs incurred in the fourth quarter of 2020 to be in a range of $64 to $74 million and remain on track to be within Laredo’s full-year 2020 budget of $340 to $350 million.

Increased Oil Hedges

For the remainder of 2020, Laredo has hedged 2.1 million barrels of oil, with 1.5 million barrels of oil swapped at a weighted-average price of $59.35 WTI per barrel and 0.6 million barrels of oil swapped at a weighted-average price of $63.07 Brent per barrel. For 2021, the Company has hedged 80% of expected oil production, with 8.1 million barrels of oil at a weighted-average floor price of $50.80 Brent per barrel.

Please see the table in the appendix of Laredo’s Third-Quarter 2020 Earnings Presentation posted to the Company’s website for the full details of the Company’s commodity derivatives.

Liquidity

At September 30, 2020, the Company had outstanding borrowings of $235 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $446 million. Including cash and cash equivalents of $40 million, total liquidity was $486 million.

At November 2, 2020, the Company had outstanding borrowings of $220 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $461 million. Including cash and cash equivalents of $28 million, total liquidity was $489 million.

Fourth-Quarter and Full-Year 2020 Guidance

The table below reflects the Company’s increased fourth-quarter and full-year guidance for total and oil production for 2020. The increase in total production guidance for fourth-quarter and full-year 2020 reflects the continued outperformance versus expectations of natural gas production on the Company’s established acreage position. This represent an 8% increase at the midpoint from full-year 2020 guidance issued with first-quarter 2020 results and a 2% increase from full-year 2020 guidance issued with second-quarter 2020 results. The Company raised the low-end of oil production guidance by 2%, compared to previous guidance issued with second-quarter 2020 results, for both fourth-quarter and full-year 2020 as established acreage wells have continued to perform better than type-curve expectations and the performance of the five-well Western Glasscock package has improved. The increase in the high-end of guidance includes the possibility of the Company’s 15-well package in Howard County beginning to produce oil prior to the end of 2020.

4Q-20E FY-20E
Total production (MBOE per day) 82.0 – 84.0 87.6 – 88.1
Oil production (MBOPD) 21.0 – 23.0 26.6 – 27.1

The table below reflects the Company’s guidance for selected revenue and expense items for the fourth quarter of 2020.

4Q-20E
Average sales price realizations (excluding derivatives):
Oil (% of WTI) 95%
NGL (% of WTI) 26%
Natural gas (% of Henry Hub) 49%
Other ($ MM):
Net income (expense) of purchased oil ($4.3)
Net midstream service income (expense) $0.75
Selected average costs & expenses:
Lease operating expenses ($/BOE) $2.80
Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) 7.25%
Transportation and marketing expenses ($/BOE) $1.95
General and administrative expenses (excluding LTIP, $/BOE) $1.25
General and administrative expenses (LTIP cash and non-cash, $/BOE) $0.35
Depletion, depreciation and amortization ($/BOE) $6.00

Conference Call Details

On Thursday, November 5, 2020, at 7:30 a.m. CT, Laredo will host a conference call to discuss its third-quarter 2020 financial and operating results and management’s outlook, the content of which is not part of this earnings release. A slide presentation providing summary financial and statistical information that will be discussed on the call will be posted to the Company’s website and available for review. The Company invites interested parties to listen to the call via the Company’s website at www.laredopetro.com, under the tab for “Investor Relations.” Portfolio managers and analysts who would like to participate on the call should dial 877.930.8286 (international dial-in 253.336.8309), using conference code 2755456, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call on November 5, 2020 through Thursday, November 12, 2020. Participants may access this replay by dialing 855.859.2056, using conference code 2755456.

About Laredo

Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo’s business strategy is focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas.

Additional information about Laredo may be found on its website at www.laredopetro.com.

Forward-Looking Statements
This press release and any oral statements made regarding the contents of this release, including in the conference call referenced herein, contain forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries (“OPEC+”), the outbreak of disease, such as the coronavirus (“COVID-19”) pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic and actions by OPEC+, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, possible impacts of litigation and regulations, the impact of the Company’s transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to our business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2019, Amendment No. 1 to its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, its Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this press release and the conference call, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. “EURs” from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. “Type curve” refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The “standardized measure” of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.

This press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), such as Adjusted EBITDA, Cash Flow and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, please see the supplemental financial information at the end of this press release.

Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of the Company’s derivative transactions.

All amounts, dollars and percentages presented in this press release are rounded and therefore approximate.

Net Debt
Net Debt, a non-GAAP financial measure, is calculated as long-term debt less cash. Management believes Net Debt is useful to management and investors in determining the Company’s leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt.

Free Cash Flow
Free Cash Flow, a non-GAAP financial measure, represents net cash provided by operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs. Management believes Free Cash Flow is useful to management and investors in evaluating the operating trends in its business due to production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.

Laredo Petroleum, Inc.
Selected operating data

Three months ended September 30, Nine months ended September 30,
2020 2019 2020 2019
(unaudited) (unaudited)
Sales volumes:
Oil (MBbl) 2,311 2,560 7,809 7,865
NGL (MBbl) 2,760 2,344 7,979 6,643
Natural gas (MMcf) 18,072 15,790 52,401 43,731
Oil equivalents (MBOE)(1)(2) 8,083 7,537 24,522 21,797
Average daily oil equivalent sales volumes (BOE/D)(2) 87,857 81,921 89,496 79,843
Average daily oil sales volumes (BOPD)(2) 25,120 27,830 28,500 28,810
Average sales prices(2):
Oil ($/Bbl)(3) $ 40.38 $ 55.35 $ 36.29 $ 54.79
NGL ($/Bbl)(3) $ 9.04 $ 8.75 $ 6.23 $ 11.28
Natural gas ($/Mcf)(3) $ 0.79 $ 0.48 $ 0.56 $ 0.48
Average sales price ($/BOE)(3) $ 16.39 $ 22.52 $ 14.78 $ 24.18
Oil, with commodity derivatives ($/Bbl)(4) $ 59.93 $ 56.15 $ 55.35 $ 53.59
NGL, with commodity derivatives ($/Bbl)(4) $ 10.46 $ 13.43 $ 8.35 $ 13.83
Natural gas, with commodity derivatives ($/Mcf)(4) $ 0.92 $ 1.01 $ 0.92 $ 1.09
Average sales price, with commodity derivatives ($/BOE)(4) $ 22.76 $ 25.38 $ 22.32 $ 25.75
Selected average costs and expenses per BOE sold(2):
Lease operating expenses $ 2.45 $ 3.00 $ 2.55 $ 3.16
Production and ad valorem taxes 1.08 1.47 1.02 1.36
Transportation and marketing expenses 1.63 0.74 1.54 0.70
Midstream service expenses 0.13 0.16 0.12 0.16
General and administrative (excluding LTIP) 1.16 1.46 1.16 1.72
Total selected operating expenses $ 6.45 $ 6.83 $ 6.39 $ 7.10
General and administrative (LTIP):
LTIP cash $ 0.03 $ $ 0.04 $
LTIP non-cash $ 0.23 $ (0.28 ) $ 0.22 $ 0.18
Depletion, depreciation and amortization $ 5.82 $ 9.17 $ 7.13 $ 9.08

_______________________________________________________________________________

(1) BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2) The numbers presented are calculated based on actual amounts that are not rounded.
(3) Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.
(4) Price reflects the after-effects of the Company’s commodity derivative transactions on it’s average sales prices. The Company’s calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods.

Laredo Petroleum, Inc.
Condensed consolidated statements of operations

  Three months ended September 30, Nine months ended September 30,
(in thousands, except per share data) 2020 2019 2020 2019
(unaudited) (unaudited)
Revenues:
Oil, NGL and natural gas sales $ 132,462 $ 169,751 $ 362,490 $ 526,990
Midstream service revenues 1,751 3,079 6,715 8,572
Sales of purchased oil 39,334 20,739 119,922 83,597
Total revenues 173,547 193,569 489,127 619,159
Costs and expenses:
Lease operating expenses 19,840 22,597 62,471 68,838
Production and ad valorem taxes 8,753 11,085 24,935 29,632
Transportation and marketing expenses 13,161 5,583 37,886 15,233
Midstream service expenses 1,073 1,191 3,058 3,401
Costs of purchased oil 42,720 20,741 138,134 83,604
General and administrative 11,473 8,852 34,694 41,427
Organizational restructuring expenses 5,965 4,200 16,371
Depletion, depreciation and amortization 47,015 69,099 174,891 197,900
Impairment expense 196,088 397,890 789,235 397,890
Other operating expenses 1,102 1,005 3,325 3,077
Total costs and expenses 341,225 544,008 1,272,829 857,373
Operating loss (167,678 ) (350,439 ) (783,702 ) (238,214 )
Non-operating income (expense):
Gain (loss) on derivatives, net (45,250 ) 96,684 162,049 136,713
Interest expense (26,828 ) (15,191 ) (78,870 ) (46,503 )
Litigation settlement 42,500
Loss on extinguishment of debt (13,320 )
Other, net (74 ) 1,850 (1,552 ) 3,954
Total non-operating income (expense), net (72,152 ) 83,343 68,307 136,664
Loss before income taxes (239,830 ) (267,096 ) (715,395 ) (101,550 )
Income tax benefit:
Deferred 2,398 2,467 7,154 812
Total income tax benefit 2,398 2,467 7,154 812
Net loss $ (237,432 ) $ (264,629 ) $ (708,241 ) $ (100,738 )
Net loss per common share(1):
Basic $ (20.32 ) $ (22.86 ) $ (60.76 ) $ (8.72 )
Diluted $ (20.32 ) $ (22.86 ) $ (60.76 ) $ (8.72 )
Weighted-average common shares outstanding(1):
Basic 11,686 11,578 11,657 11,558
Diluted 11,686 11,578 11,657 11,558

_______________________________________________________________________________

(1) Net loss per common share and weighted-average common shares outstanding were retroactively adjusted for the Company’s 1-for-20 reverse stock split effective June 1, 2020.

Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows

  Three months ended September 30, Nine months ended September 30,
(in thousands) 2020 2019 2020 2019
(unaudited) (unaudited)
Cash flows from operating activities:
Net loss $ (237,432 ) $ (264,629 ) $ (708,241 ) $ (100,738 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-settled equity-based compensation, net 2,041 (1,739 ) 6,111 5,244
Depletion, depreciation and amortization 47,015 69,099 174,891 197,900
Impairment expense 196,088 397,890 789,235 397,890
Mark-to-market on derivatives:
(Gain) loss on derivatives, net 45,250 (96,684 ) (162,049 ) (136,713 )
Settlements received for matured derivatives, net 51,840 25,245 186,435 48,827
Settlements received (paid) for early-terminated commodity derivatives, net 6,340 6,340 (5,409 )
Premiums paid for commodity derivatives (1,415 ) (51,070 ) (7,664 )
Loss on extinguishment of debt 13,320
Deferred income tax benefit (2,398 ) (2,467 ) (7,154 ) (812 )
Other, net 5,099 2,606 17,956 14,795
Cash flows from operating activities before changes in operating assets and liabilities, net 113,843 127,906 265,774 413,320
Change in current assets and liabilities, net (8,360 ) (21,183 ) 19,098 (48,305 )
Change in noncurrent assets and liabilities, net (3,425 ) (1,124 ) (11,252 ) 1,853
Net cash provided by operating activities 102,058 105,599 273,620 366,868
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net (23,563 ) (2,880 )
Capital expenditures:
Oil and natural gas properties (36,338 ) (83,566 ) (278,277 ) (368,182 )
Midstream service assets (756 ) (1,292 ) (2,517 ) (6,741 )
Other fixed assets (955 ) (755 ) (3,024 ) (1,720 )
Proceeds from dispositions of capital assets, net of selling costs 514 5,911 1,242 6,847
Net cash used in investing activities (37,535 ) (79,702 ) (306,139 ) (372,676 )
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility 45,000 45,000 80,000
Payments on Senior Secured Credit Facility (85,000 ) (50,000 ) (185,000 ) (85,000 )
Issuance of January 2025 Notes and January 2028 Notes 1,000,000
Extinguishment of debt (808,855 )
Payments for debt issuance costs (18,451 )
Other, net (12 ) (4 ) (774 ) (2,650 )
Net cash (used in) provided by financing activities (40,012 ) (50,004 ) 31,920 (7,650 )
Net increase (decrease) in cash and cash equivalents 24,511 (24,107 ) (599 ) (13,458 )
Cash and cash equivalents, beginning of period 15,747 55,800 40,857 45,151
Cash and cash equivalents, end of period $ 40,258 $ 31,693 $ 40,258 $ 31,693

Laredo Petroleum, Inc.
Total Costs Incurred

The following table presents the components of the Company’s costs incurred, excluding non-budgeted acquisition costs, for the periods presented:

Three months ended September 30, Nine months ended September 30,
(in thousands) 2020 2019 2020 2019
(unaudited) (unaudited)
Oil and natural gas properties $ 41,128 $ 76,837 $ 269,937 $ 365,839
Midstream service assets 1,103 1,147 2,697 7,584
Other fixed assets 495 999 3,092 1,966
Total costs incurred, excluding non-budgeted acquisition costs $ 42,726 $ 78,983 $ 275,726 $ 375,389

Laredo Petroleum, Inc.
Supplemental reconciliations of GAAP to non-GAAP financial measures

Non-GAAP financial measures

The non-GAAP financial measures of Free Cash Flow, Adjusted Net Income and Adjusted EBITDA, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP financial measures should be considered in conjunction with net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss or cash flows from operating activities. Free Cash Flow, Adjusted Net Income and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.

Free Cash Flow (Unaudited)

Free Cash Flow, a non-GAAP financial measure, does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in the Company’s business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.

The following table presents a reconciliation of net cash provided by operating activities (GAAP) to cash flows from operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs, for the calculation of Free Cash Flow (non-GAAP) for the periods presented:

Three months ended September 30, Nine months ended September 30,
(in thousands) 2020 2019 2020 2019
(unaudited) (unaudited)
Net cash provided by operating activities $ 102,058 $ 105,599 $ 273,620 $ 366,868
Less:
Change in current assets and liabilities, net (8,360 ) (21,183 ) 19,098 (48,305 )
Change in noncurrent assets and liabilities, net (3,425 ) (1,124 ) (11,252 ) 1,853
Cash flows from operating activities before changes in operating assets and liabilities, net 113,843 127,906 265,774 413,320
Less costs incurred, excluding non-budgeted acquisition costs:
Oil and natural gas properties(1) 41,128 76,837 269,937 365,839
Midstream service assets(1) 1,103 1,147 2,697 7,584
Other fixed assets 495 999 3,092 1,966
Total costs incurred, excluding non-budgeted acquisition costs 42,726 78,983 275,726 375,389
Free Cash Flow (non-GAAP) $ 71,117 $ 48,923 $ (9,952 ) $ 37,931

_____________________________________________________________________________

(1) Includes capitalized share-settled equity-based compensation and asset retirement costs.

Adjusted Net Income (Unaudited)

Adjusted Net Income is a non-GAAP financial measure that the Company defines as income or loss before income taxes plus adjustments for mark-to-market on derivatives, premiums paid for commodity derivatives that matured during the period, impairment expense, gains or losses on disposal of assets, other non-recurring income and expenses and adjusted income tax expense. The Company believes Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare the Company’s performance to other oil and natural gas companies by excluding from the calculation items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors.

The following table presents a reconciliation of loss before income taxes (GAAP) to Adjusted Net Income (non-GAAP):

Three months ended September 30, Nine months ended September 30,
(in thousands, except per share data) 2020 2019 2020 2019
(unaudited) (unaudited)
Loss before income taxes $ (239,830 ) $ (267,096 ) $ (715,395 ) $ (101,550 )
Plus:
Mark-to-market on derivatives:
(Gain) loss on derivatives, net 45,250 (96,684 ) (162,049 ) (136,713 )
Settlements received for matured derivatives, net 51,840 25,245 186,435 48,827
Settlements received (paid) for early-terminated commodity derivatives, net 6,340 6,340 (5,409 )
Premiums paid for commodity derivatives that matured during the period(1) (1,415 ) (477 ) (7,664 )
Organizational restructuring expenses 5,965 4,200 16,371
Impairment expense 196,088 397,890 789,235 397,890
Loss on extinguishment of debt 13,320
Litigation settlement (42,500 )
(Gain) loss on disposal of assets, net 607 (1,294 ) 1,057 315
Write-off of debt issuance costs 1,103
Adjusted income before adjusted income tax expense 60,295 62,611 123,769 169,567
Adjusted income tax expense(2) (13,265 ) (13,774 ) (27,229 ) (37,305 )
Adjusted Net Income $ 47,030 $ 48,837 $ 96,540 $ 132,262
Net loss per common share(3):
Basic $ (20.32 ) $ (22.86 ) $ (60.76 ) $ (8.72 )
Diluted $ (20.32 ) $ (22.86 ) $ (60.76 ) $ (8.72 )
Adjusted Net Income per common share(3):
Basic $ 4.02 $ 4.22 $ 8.28 $ 11.44
Diluted $ 4.02 $ 4.22 $ 8.28 $ 11.44
Adjusted diluted $ 4.02 $ 4.22 $ 8.25 $ 11.41
Weighted-average common shares outstanding(3):
Basic 11,686 11,578 11,657 11,558
Diluted 11,686 11,578 11,657 11,558
Adjusted diluted 11,691 11,585 11,705 11,587

_______________________________________________________________________________

(1) Reflects premiums incurred previously or upon settlement that are attributable to derivatives settled in the respective periods presented and were not a result of a hedge restructuring.
(2) Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended September 30, 2020 and 2019.
(3) Net loss per common share, Adjusted Net Income per common share and weighted-average common shares outstanding were retroactively adjusted for the Company’s 1-for-20 reverse stock split effective June 1, 2020.

Adjusted EBITDA (Unaudited)

Adjusted EBITDA is a non-GAAP financial measure that the Company defines as net income or loss plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid for commodity derivatives that matured during the period, accretion expense, gains or losses on disposal of assets, interest expense, income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Adjusted EBITDA is useful to an investor in evaluating the Company’s operating performance because this measure:

  • is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;
  • helps investors to more meaningfully evaluate and compare the results of the Company’s operations from period to period by removing the effect of its capital structure from its operating structure; and
  •  is used by management for various purposes, including as a measure of operating performance, in presentations to the Company’s board of directors and as a basis for strategic planning and forecasting.

There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company’s net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Adjusted EBITDA reported by different companies. The Company’s measurements of Adjusted EBITDA for financial reporting as compared to compliance under its debt agreements differ.

The following table presents a reconciliation of net loss (GAAP) to Adjusted EBITDA (non-GAAP) for the periods presented:

  Three months ended September 30, Nine months ended September 30,
(in thousands) 2020 2019 2020 2019
(unaudited) (unaudited)
Net loss $ (237,432 ) $ (264,629 ) $ (708,241 ) $ (100,738 )
Plus:
Share-settled equity-based compensation, net 2,041 (1,739 ) 6,111 5,244
Depletion, depreciation and amortization 47,015 69,099 174,891 197,900
Impairment expense 196,088 397,890 789,235 397,890
Organizational restructuring expenses 5,965 4,200 16,371
Mark-to-market on derivatives:
(Gain) loss on derivatives, net 45,250 (96,684 ) (162,049 ) (136,713 )
Settlements received for matured derivatives, net 51,840 25,245 186,435 48,827
Settlements received (paid) for early-terminated commodity derivatives, net 6,340 6,340 (5,409 )
Premiums paid for commodity derivatives that matured during the period(1) (1,415 ) (477 ) (7,664 )
Accretion expense 1,102 1,005 3,325 3,077
(Gain) loss on disposal of assets, net 607 (1,294 ) 1,057 315
Interest expense 26,828 15,191 78,870 46,503
Loss on extinguishment of debt 13,320
Litigation settlement (42,500 )
Write-off of debt issuance costs 1,103
Income tax benefit (2,398 ) (2,467 ) (7,154 ) (812 )
Adjusted EBITDA $ 137,281 $ 146,167 $ 386,966 $ 422,291

_____________________________________________________________________________

(1) Reflects premiums incurred previously or upon settlement that are attributable to derivatives settled in the respective periods presented and were not a result of a hedge restructuring.

Ron Hagood: 918.858.5504 – [email protected]



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