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Northern Oil and Gas, Inc. Announces Third Quarter 2019 Results

MINNEAPOLIS--(BUSINESS WIRE)--

  • Third quarter production increased 53% over the prior year, and 17% sequentially, averaging 40,786 barrels of oil equivalent (“Boe”) per day.
  • Cash flow from operations, excluding a $32.5 million net decrease from changes in working capital and other items, was $103.5 million for the third quarter, an 11% increase versus the second quarter.
  • Organic drilling and development capital expenditures totaled $80.1 million during the third quarter.
  • Northern closed the VEN Bakken acquisition and also added another 13.3 net wells to production during the third quarter, which helped offset the curtailments, shut-ins and completion delays that negatively impacted production by an estimated 4,500 Boe per day during the quarter.
  • Ground Game success continued in the third quarter, with $9.9 million of acquisition capital and an additional $23.0 million of associated development capital allocated to drive cash flow for shareholder returns in 2020.

Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s third quarter results.

Third quarter 2019 production totaled 3.8 million Boe and averaged 40,786 Boe per day, a 53% increase from the prior year and a 17% increase sequentially. Oil and gas sales in the third quarter totaled $158.0 million. Net income in the third quarter was $94.4 million or $0.24 per diluted share. Adjusted Net Income in the third quarter was $36.3 million or $0.09 per diluted share. Adjusted EBITDA totaled $124.4 million in the third quarter, a 27% increase from the prior year. (See “Non-GAAP Financial Measures” below.)

“Strong net well additions from our organic well opportunities and the success we have had in our ground game acquisitions generated strong production growth during the quarter,” commented Brandon Elliott, Chief Executive Officer. “While well performance and net well additions have remained robust, they did not completely offset 4,500 Boe per day of shut-ins and curtailments during the quarter. The good news is we expect the well performance and net well additions to remain strong while we expect the infrastructure issues to begin to subside as we close out 2019. Future cash flows will support plans to reduce debt ratios and return capital to shareholders in 2020.”

Production and Operating Costs

Total third quarter production was 3.8 million Boe, driven by the closing of the VEN Bakken acquisition and an additional 13.3 net wells added to production during the quarter. Strong well results were offset by continued infrastructure-driven constraints. Midstream system expansions, while beginning to come online, did not offset the negative effects on production and natural gas and NGL prices during the quarter. Oil price differentials averaged $5.48 per barrel, a 4% increase from the second quarter of 2019. Ongoing production curtailments resulted in a 5% sequential increase in lease operating expenses (“LOE”) to $8.62 per Boe in the third quarter. General and administrative expenses were $1.12 per Boe in the third quarter.

2019 Capital Allocation and Ground Game Activity

Northern continues to focus capital to the highest returns on capital employed in an effort to grow cash flow as it prepares to begin returning capital to shareholders in 2020. During the third quarter, Northern spent $80.1 million on organic development capital and an additional $32.9 million related to its ground game acquisition strategy (“Ground Game”), which is Northern's regular acquisition activity excluding larger, separately announced deals such as the recent VEN Bakken acquisition. Of the total Ground Game spend, $9.9 million was acquisition capital and an additional $23.0 million was associated development capital.

The third quarter was extremely active for Northern’s Ground Game. With many operators and non-operating participants seeking to reduce their short term capital obligations, the landscape for high return opportunities, particularly for near term drilling, has been robust. In the third quarter, Northern acquired approximately 3,100 net acres and 4.4 net wells in process. Of those net wells in process, approximately 2.0 net wells came online in the third quarter, 1.1 of which came online ahead of schedule late in the quarter. Northern's Ground Game success in 2019 will allow it to moderate its acquisition activity in 2020, as the Company looks to harvest cash flows from its 2019 acquisitions. Northern will, however, continue to monitor and evaluate potential acquisitions for distressed and high-return opportunities.

2019 Production Guidance Updated for Ground Game Acquisitions and Continued Curtailments

Northern expects to add 33 – 34 net organic wells to production in 2019. Due to Ground Game success over the last 12 months and an acceleration in development activity, Northern expects to add an additional 5 – 7 net wells to production from the Ground Game, for a total of 38 – 41 total net wells added to production during 2019.

Additional information regarding Northern’s current expectations are included in the tables below.

2019 Production (Boe per day):

Current

 

Previous

1st Quarter – Actual

34,568

 

 

2nd Quarter – Actual

34,965

 

 

3rd Quarter – Actual

40,786

 

 

4th Quarter – Estimate

43,500 – 44,500

 

43,500 – 44,500

Annual – Estimate

38,500 – 38,750

 

38,650 – 39,150

 

 

 

 

2019 Guidance Ranges (in millions, except for net well data):

Current

 

Previous

Organic(1) Net Wells Added to Production

33 – 34

 

33 – 34

Organic(1) Drilling & Completion (D&C) Capital

$265 – $285

 

$265 – $285

Ground Game 2019E Net Wells Added to Production

5 – 7

 

3 – 5

Ground Game Acquisition Capital

$30 – $40

 

$25 – $50

Ground Game D&C Capital

$40 – $70

 

$30 – $60

 

_____________

(1)

Organic includes estimated net wells and D&C capital from recently acquired VEN Bakken assets (post-closing).

2019 Full Year Operating Expenses Guidance:

Current

 

Previous

 

 

 

Production Expenses (per Boe)

$8.00 – $8.50

 

$8.00 – $8.50

Production Taxes

10% of crude oil

 

~ 9.3% of oil and

sales; $0.075 per

 

gas sales

mcf of gas

 

 

General and Administrative Expense (per Boe):

 

 

 

Cash

$0.95 – $1.15

 

$0.95 – $1.15

Non-Cash

$0.50

 

$0.50

 

 

 

 

Average Differential to NYMEX WTI

$4.50 – $6.50

 

$4.50 – $6.50

THIRD QUARTER 2019 RESULTS

The following tables set forth selected operating and financial data for the periods indicated.

 

Three Months Ended September 30,

 

2019

 

2018

 

% Change

Net Production:

 

 

 

 

 

Oil (Bbl)

3,002,789

 

2,064,092

 

45

%

Natural Gas and NGLs (Mcf)

4,496,860

 

2,358,162

 

91

%

Total (Boe)

3,752,266

 

2,457,119

 

53

%

 

 

 

 

 

 

Average Daily Production:

 

 

 

 

 

Oil (Bbl)

32,639

 

22,436

 

45

%

Natural Gas and NGLs (Mcf)

48,879

 

25,632

 

91

%

Total (Boe)

40,786

 

26,708

 

53

%

 

 

 

 

 

 

Average Sales Prices:

 

 

 

 

 

Oil (per Bbl)

$

50.90

 

$

65.45

 

(22)

%

Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)

6.12

 

(6.26)

 

 

Oil Net of Settled Derivatives (per Bbl)

57.02

 

59.19

 

(4)

%

Natural Gas and NGLs (per Mcf)

1.15

 

4.41

 

(74)

%

Realized Price on a Boe Basis Including all Realized Derivative Settlements

47.00

 

53.96

 

(13)

%

 

 

 

 

 

 

Costs and Expenses (per Boe):

 

 

 

 

 

Production Expenses

$

8.62

 

$

7.39

 

17

%

Production Taxes

4.10

 

5.53

 

(26)

%

General and Administrative Expense

1.12

 

1.90

 

(41)

%

Depletion, Depreciation, Amortization and Accretion

14.81

 

12.31

 

20

%

 

 

 

 

 

 

Net Producing Wells at Period End

444.0

 

284.3

 

56

%

HEDGING

Northern hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following tables summarize Northern’s open crude oil derivative and basis swap contracts scheduled to settle after September 30, 2019.

Crude Oil Derivative Swaps

Contract Period

 

Volume (Bbls)

 

Weighted Average Price (per Bbl)

2019:

 

 

 

 

4Q

 

2,460,411

 

$58.96

2020:

 

 

 

 

1Q

 

2,490,106

 

$59.15

2Q

 

2,431,778

 

$58.44

3Q

 

2,340,348

 

$58.48

4Q

 

2,165,362

 

$58.00

2021:

 

 

 

 

1Q

 

1,690,050

 

$56.73

2Q

 

1,587,958

 

$57.24

3Q

 

1,418,410

 

$54.35

4Q

 

1,409,506

 

$54.37

2022(1):

 

 

 

 

1Q

 

453,780

 

$53.07

2Q

 

312,280

 

$52.30

3Q

 

306,576

 

$52.33

4Q

 

300,230

 

$52.35

_____________

(1)

The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 2.4 million barrels for 2022 are exercisable on or about December 31, 2021. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase as follows for 2022: (i) for the first quarter of 2022, by 807,750 barrels at a weighted average price of $54.89 per barrel, (ii) for the second quarter of 2022, by 816,725 barrels at a weighted average price of $54.89 per barrel, (iii) for the third quarter of 2022, by 365,700 barrels at a weighted average price of $55.04 per barrel, and (iv) for the fourth quarter of 2022, by 365,700 barrels at a weighted average price of $55.04 per barrel.

Crude Oil Derivative Basis Swaps(1)

 

 

 

 

Weighted Average Differential

Contract Period

Total Volumes (Bbls)

($/Bbl)

10/01/2019 - 12/31/2019

 

951,000

 

($2.40)

_____________

(1)

Basis swaps are settled using the TMX UHC 1a index, as published by NGX.

LIQUIDITY

As of September 30, 2019, Northern had $1.9 million in cash and $327.0 million outstanding on its revolving credit facility. Northern had total liquidity of $99.9 million as of September 30, 2019, consisting of cash and borrowing availability under the revolving credit facility.

CAPITAL EXPENDITURES & DRILLING ACTIVITY

 

 

Three Months Ended

(in millions, except for net well data)

September 30, 2019

Capital Expenditures Incurred:

 

 

Organic Drilling and Development Capital Expenditures

 

$

80.1

Ground Game Acquisition Capital Expenditures

 

$

9.9

Ground Game Drilling and Development Capital Expenditures

 

$

23.0

Acquisition of Oil and Natural Gas Properties and Other

 

$

325.7

 

 

 

Net Wells Added to Production

 

13.3

 

 

 

Net Producing Wells (Period-End)

 

444.0

 

 

 

Net Wells in Process (Period-End)

 

24.2

Increase in Wells in Process over 2018 Year-End

 

1.4

 

 

 

Weighted Average AFE for Wells Elected to During the Third Quarter

 

$

7.7

Weighted Average AFE for Wells Elected to Year-to-Date

 

$

7.9

Capitalized costs are a function of the number of net well additions during the period, and changes in wells in process from the prior year-end. Capital expenditures attributable to the 1.4 well increase in net wells in process during the nine months ended September 30, 2019 are reflected in the amounts incurred year-to-date for drilling and development capital expenditures.

ACREAGE

As of September 30, 2019, Northern controlled leasehold of approximately 183,518 net acres targeting the Bakken and Three Forks formations of the Williston Basin, and approximately 90% of this total acreage position was developed, held by production, or held by operations.

THIRD QUARTER 2019 EARNINGS RELEASE CONFERENCE CALL

In conjunction with Northern’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Tuesday, November 12, 2019 at 10:00 a.m. Central Time.

Those wishing to listen to the conference call may do so via the company’s website, www.northernoil.com, or by phone as follows:

Dial-In Number: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13696040 - Northern Oil and Gas, Inc. Third Quarter 2019 Conference Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13696040 - Replay will be available through November 19, 2019

UPCOMING CONFERENCE SCHEDULE

Bank of America 2019 Leveraged Finance Conference
   December 2 - 4, 2019, Boca Raton, FL

Capital One Securities 14th Annual Energy Conference
   December 10 - 12, 2019, Houston, TX

Piper Jaffray 20th Annual Energy Conference
   March 23 - 25, 2020, Las Vegas, NV

ABOUT NORTHERN OIL AND GAS

Northern Oil and Gas, Inc. is an exploration and production company with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana. More information about Northern Oil and Gas, Inc. can be found at www.northernoil.com.

SAFE HARBOR

This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on Northern’s current properties, infrastructure constraints and related factors affecting Northern’s properties, Northern’s ability to acquire additional development opportunities, changes in Northern’s reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which Northern conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern’s ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern’s operations, products and prices.

Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control. Northern does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws.

CONDENSED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

 

Three Months Ended

 

Nine Months Ended

September 30,

 

September 30,

(In thousands, except share and per share data)

2019

 

2018

 

2019

 

2018

REVENUES

 

 

 

 

 

 

 

Oil and Gas Sales

$

157,989

 

$

145,416

 

$

440,519

 

$

341,343

Gain (Loss) on Derivative Instruments, Net

 

75,892

 

 

(43,148)

 

 

(27,139)

 

 

(105,622)

Other Revenue

 

3

 

 

2

 

 

10

 

 

5

Total Revenues

 

233,883

 

 

102,269

 

 

413,389

 

 

235,729

 

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

 

 

Production Expenses

 

32,347

 

 

18,161

 

 

83,146

 

 

45,198

Production Taxes

 

15,391

 

 

13,579

 

 

41,944

 

 

31,633

General and Administrative Expenses

 

4,206

 

 

4,674

 

 

15,506

 

 

9,593

Depletion, Depreciation, Amortization and Accretion

 

55,566

 

 

30,258

 

 

146,791

 

 

71,485

Impairment of Other Current Assets

 

5,275

 

 

 

7,969

 

Total Operating Expenses

 

112,784

 

 

66,673

 

 

295,355

 

 

157,909

 

 

 

 

 

 

 

 

INCOME FROM OPERATIONS

 

121,100

 

 

35,597

 

 

118,034

 

 

77,820

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

Interest Expense, Net of Capitalization

 

(21,510)

 

 

(20,438)

 

 

(58,836)

 

 

(65,948)

Loss on the Extinguishment of Debt

 

 

(9,542)

 

 

(425)

 

 

(100,375)

Debt Exchange Derivative Gain/(Loss)

 

(23)

 

 

13,063

 

 

1,390

 

 

13,063

Contingent Consideration Loss

 

(5,262)

 

 

 

(28,633)

 

Other Income (Expense)

 

75

 

 

299

 

 

88

 

 

838

Total Other Income (Expense)

 

(26,719)

 

 

(16,618)

 

 

(86,416)

 

 

(152,423)

 

 

 

 

 

 

 

 

INCOME (LOSS) BEFORE INCOME TAXES

 

94,381

 

 

18,979

 

 

31,619

 

 

(74,603)

 

 

 

 

 

 

 

 

INCOME TAX PROVISION (BENEFIT)

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS)

$

94,381

 

$

18,979

 

$

31,619

 

$

(74,603)

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Basic

$

0.24

 

$

0.06

 

$

0.08

 

$

(0.40)

Net Income (Loss) Per Common Share – Diluted

$

0.24

 

$

0.06

 

$

0.08

 

$

(0.40)

Weighted Average Shares Outstanding – Basic

 

396,044,887

 

 

300,517,497

 

 

382,044,068

 

 

188,152,998

Weighted Average Shares Outstanding – Diluted

 

396,530,767

 

 

301,755,419

 

 

382,744,304

 

 

188,152,998

CONDENSED BALANCE SHEETS

 

(In thousands, except par value and share data)

September 30, 2019

 

December 31, 2018

ASSETS

(Unaudited)

 

 

Current Assets:

 

 

 

Cash and Cash Equivalents

$

1,901

 

$

2,358

Accounts Receivable, Net

103,226

 

96,353

Advances to Operators

1,314

 

268

Prepaid Expenses and Other

2,717

 

12,360

Derivative Instruments

62,531

 

115,870

Income Tax Receivable

420

 

1,205

Total Current Assets

172,110

 

228,415

 

 

 

 

Property and Equipment:

 

 

 

Oil and Natural Gas Properties, Full Cost Method of Accounting

 

 

 

Proved

4,043,897

 

3,431,428

Unproved

11,145

 

4,307

Other Property and Equipment

1,999

 

998

Total Property and Equipment

4,057,041

 

3,436,732

Less – Accumulated Depreciation, Depletion and Impairment

(2,380,086)

 

(2,233,987)

Total Property and Equipment, Net

1,676,955

 

1,202,745

 

 

 

 

Derivative Instruments

42,682

 

61,843

Deferred Income Taxes

420

 

420

Other Noncurrent Assets, Net

9,842

 

10,223

 

 

 

 

Total Assets

$

1,902,009

 

$

1,503,645

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:

 

 

 

Accounts Payable

$

112,698

 

$

55,015

Accrued Liabilities

90,114

 

83,237

Accrued Interest

17,567

 

16,468

Debt Exchange Derivative

 

18,183

Contingent Consideration

10,058

 

58,069

Other Current Liabilities

387

 

555

Total Current Liabilities

230,824

 

231,526

 

 

 

 

Long-term Debt, Net

1,140,072

 

830,203

Asset Retirement Obligations

16,582

 

11,946

Other Noncurrent Liabilities

417

 

105

 

 

 

 

TOTAL LIABILITIES

$

1,387,894

 

$

1,073,780

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 8)

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY

 

 

 

Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding

 

Common Stock, Par Value $.001; 675,000,000 Shares Authorized;
404,346,470 Shares Outstanding at 9/30/2019
378,333,070 Shares Outstanding at 12/31/2018

404

 

378

Additional Paid-In Capital

1,278,976

 

1,226,371

Retained Deficit

(765,266)

 

(796,884)

Total Stockholders’ Equity

514,114

 

429,865

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

$

1,902,009

 

$

1,503,645

Non-GAAP Financial Measures

Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. Northern defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) impairment of other current assets, net of tax, (iii) loss on the extinguishment of debt, net of tax, (iv) debt exchange derivative (gain) loss, net of tax, (v) contingent consideration (gain) loss, net of tax, and (vi) certain acquisition transaction costs, net of tax. Northern defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) impairment of other current assets, (v) non-cash stock-based compensation expense, (vi) loss on the extinguishment of debt, (vii) debt exchange derivative (gain) loss, (viii) contingent consideration (gain) loss, and (ix) (gain) loss on the mark-to-market of derivative instruments. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below. Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically, management believes the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain expenses and unrealized commodity gains and losses that management believes are not indicative of Northern’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring Northern’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.

Reconciliation of Adjusted Net Income

 

Three Months Ended

 

Nine Months Ended

September 30,

 

September 30,

(In thousands, except share and per share data)

2019

 

2018

 

2019

 

2018

Net Income (Loss)

$

94,381

 

$

18,979

 

$

31,619

 

$

(74,603)

Add:

 

 

 

 

 

 

 

Impact of Selected Items:

 

 

 

 

 

 

 

(Gain) Loss on the Mark-to-Market of Derivative Instruments

(57,506)

 

30,225

 

62,806

 

72,303

Impairment of Other Current Assets

5,275

 

 

7,969

 

Loss on the Extinguishment of Debt

 

9,542

 

425

 

100,375

Debt Exchange Derivative (Gain) Loss

23

 

(13,063)

 

(1,390)

 

(13,063)

Contingent Consideration Loss

5,262

 

 

28,633

 

Acquisition Transaction Costs

1,250

 

 

1,763

 

Selected Items, Before Income Taxes

(45,696)

 

26,705

 

100,204

 

159,615

Income Tax of Selected Items(1)

(12,380)

 

(11,195)

 

(32,401)

 

(21,107)

Selected Items, Net of Income Taxes

$

(58,077)

 

$

15,510

 

$

67,803

 

$

138,508

 

 

 

 

 

 

 

 

Adjusted Net Income

$

36,304

 

$

34,489

 

$

99,422

 

$

63,905

 

 

 

 

 

 

 

 

Weighted Average Shares Outstanding – Basic

396,044,887

 

300,517,497

 

374,927,630

 

188,152,998

Weighted Average Shares Outstanding – Diluted

396,530,767

 

301,755,419

 

375,736,820

 

188,709,068

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Basic

$

0.24

 

$

0.06

 

$

0.08

 

$

(0.40)

Add:

 

 

 

 

 

 

 

Impact of Selected Items, Net of Income Taxes

(0.15)

 

0.05

 

0.19

 

0.74

Adjusted Net Income Per Common Share – Basic

$

0.09

 

$

0.11

 

$

0.27

 

$

0.34

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Diluted

$

0.24

 

$

0.06

 

$

0.08

 

$

(0.40)

Add:

 

 

 

 

 

 

 

Impact of Selected Items, Net of Income Taxes

(0.15)

 

0.05

 

0.18

 

0.74

Adjusted Net Income Per Common Share – Diluted

$

0.09

 

$

0.11

 

$

0.26

 

$

0.34

_____________

(1)

For the three and nine months ended September 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $23.6 million and $7.9 million, respectively, for a change in valuation allowance. For the three and nine months ended September 30, 2018, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $4.7 million and $18.0 million, respectively, for a reduction in valuation allowance.

Reconciliation of Adjusted EBITDA

 

 

Three Months Ended

 

Nine Months Ended

September 30,

 

September 30,

(In thousands)

 

2019

 

2018

 

2019

 

2018

Net Income (Loss)

 

$

94,381

 

$

18,979

 

$

31,619

 

$

(74,603)

Add:

 

 

 

 

 

 

 

 

Interest Expense

 

21,510

 

20,438

 

58,836

 

65,948

Income Tax Provision (Benefit)

 

 

 

 

Depreciation, Depletion, Amortization and Accretion

 

55,566

 

30,258

 

146,791

 

71,485

Impairment of Other Current Assets

 

5,275

 

 

7,969

 

Non-Cash Stock-Based Compensation

 

(114)

 

1,535

 

4,280

 

1,973

Loss on the Extinguishment of Debt

 

 

9,542

 

425

 

100,375

Debt Exchange Derivative (Gain) Loss

 

23

 

(13,063)

 

(1,390)

 

(13,063)

Contingent Consideration Loss

 

5,262

 

 

28,633

 

(Gain) Loss on the Mark-to-Market of Derivative Instruments

 

(57,506)

 

30,225

 

62,806

 

72,303

Adjusted EBITDA

 

$

124,396

 

$

97,914

 

$

339,968

 

$

224,418

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View source version on businesswire.com: https://www.businesswire.com/news/home/20191112005292/en/