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

MINNEAPOLIS--(BUSINESS WIRE)--

  • Second quarter production increased 66% over the prior year, averaging 34,965 barrels of oil equivalent (“Boe”) per day.
  • Cash flow from operations, excluding a $5.8 million net increase from changes in working capital, was $93.6 million in the second quarter, a 7% increase versus the first quarter.
  • Organic drilling and development capital expenditures totaled $71.9 million during the second quarter, a 3% decrease versus the first quarter.
  • Northern spent $10.5 million on senior note repurchases and $22.0 million on ground game acquisitions and associated development during the second quarter.

Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s second quarter results and provided updated 2019 guidance.

Second quarter 2019 production totaled 3.2 million Boe and averaged 34,965 Boe per day, a 66% increase from the prior year. Oil and gas sales in the second quarter increased 37% from the prior year to $149.8 million. Net income in the second quarter was $44.4 million or $0.12 per diluted share. Adjusted Net Income in the second quarter was $45.5 million or $0.12 per diluted share. Adjusted EBITDA totaled $110.8 million in the second quarter, a 57% increase from the prior year or 6% increase sequentially. (See “Non-GAAP Financial Measures” below.)

“We continue to execute on our 2019 capital allocation plan, focusing on the highest returns available to us including our organic well opportunities and ground game acquisitions. This approach allowed us to remain within our production guidance despite approximately 2,500 Boe per day of curtailments due to continued basin-level infrastructure constraints,” commented Brandon Elliott, Chief Executive Officer. “Strong well performance, the closing of our VEN Bakken acquisition and continued success in our ground game are expected to expand our free cash flow profile to support additional debt reduction along with a stable and consistent return of capital to shareholders.”

Production and Operating Costs

Total second quarter production was 3.2 million Boe, driven by an additional 8.1 net wells added to production during the quarter, offset in part by continued infrastructure-driven curtailments. Midstream system expansions scheduled to come online in the second half of 2019 and early 2020 are expected to alleviate curtailments late in 2019. Oil price differentials of $5.29 per barrel are trending as expected, a 15% improvement from the first quarter of 2019. Ongoing production curtailments resulted in an increase in lease operating expenses (“LOE”) to $8.21 per Boe in the second quarter. Cash general and administrative expenses were $1.13 per Boe in the second quarter, up 7% from the first quarter primarily due to transaction and legal costs associated with the VEN Bakken acquisition. Northern anticipates a one-time expense of $1.3 million for advisory fees for this transaction to be expensed in the third quarter of 2019.

2019 Cash Flow Allocation

Northern continues to closely manage its discretionary cash flow allocation in an effort to produce the highest returns on capital employed. Northern spent, in aggregate, $22.0 million in the second quarter on ground game acquisitions and associated development capital. “Ground game” refers to Northern’s regular acquisition activity excluding larger, separately announced transactions such as the recent VEN Bakken acquisition. These transactions and wells in process will serve to increase Northern’s production and cash flows in 2019 and 2020, and bring forth additional future drilling opportunities. Northern spent $10.5 million on Senior Note repurchases in the second quarter. Northern expects sequential production, cash flow and net income growth throughout the remainder of 2019 and into 2020, due to the strong success of the ground game, the closing of the VEN Bakken acquisition, and relief from infrastructure constraints.

2019 Production Guidance Updated for Ground Game Acquisitions, VEN Bakken and Continued Curtailments

Current Williston Basin activity levels remain stable, and Northern now expects, on an organic basis combined with VEN Bakken, to drill 33 – 34 net wells in 2019. In addition, Northern expects to add an additional 3 – 5 net wells during the year through its ground game acquisition strategy, for a total of 36 – 39 total net wells added to production during 2019. Northern now expects production (inclusive of six months of production from the VEN Bakken acquisition that closed on July 1, 2019) to average between 38,650 – 39,150 Boe per day for the full year of 2019. Northern’s previous cost and capital spending plan are being adjusted as well. LOE guidance is being adjusted to account for higher unit costs driven by curtailments and the higher LOE per unit costs associated with the VEN Bakken assets. Production taxes are being raised modestly, due to weaker overall gas and NGL prices in relation to crude oil prices, as a percentage of sales. Cash G&A per Boe guidance is being lowered to reflect higher expected production volumes, but partially offset by an estimated $1.9 million in transaction costs and fees incurred or expected to be incurred in connection with the VEN Bakken acquisition.

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

 

34,500 – 35,500

3rd Quarter – Estimate

41,500 – 42,500

 

4th Quarter – Estimate

43,500 – 44,500

 

Annual – Estimate

38,650 – 39,150

 

35,000 – 36,000

 

 

 

 

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

Current

 

Previous

Organic(1) Net Wells Added to Production

33 – 34

 

28 – 32

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

$265 – $285

 

$227 – $260

Ground Game 2019E Net Wells Added to Production

3 – 5

 

Ground Game Acquisition Capital

$25 – $50

 

$20 – $25

Ground Game D&C Capital

$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

 

$6.75 – $7.75

Production Taxes (% of Oil & Gas Sales)

~ 9.3%

 

~ 9.1%

General and Administrative Expense (per Boe):

 

 

 

Cash(2)

$0.95 – $1.15

 

$1.00 – $1.25

Non-Cash

$0.50

 

$0.50

 

 

 

 

Average Differential to NYMEX WTI

$4.50 – $6.50

 

$4.50 – $6.50

(2) Inclusive of approximately $1.9 million of transaction costs and fees incurred or expected to be incurred in connection with the VEN Bakken acquisition.

SECOND QUARTER 2019 RESULTS

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

 

Three Months Ended June 30,

 

2019

 

2018

 

% Change

Net Production:

 

 

 

 

 

Oil (Bbl)

 

2,562,513

 

 

1,625,788

 

 

58

%

Natural Gas and NGLs (Mcf)

 

3,715,936

 

 

1,736,651

 

 

114

%

Total (Boe)

 

3,181,835

 

 

1,915,230

 

 

66

%

 

 

 

 

 

 

Average Daily Production:

 

 

 

 

 

Oil (Bbl)

 

28,159

 

 

17,866

 

 

58

%

Natural Gas and NGLs (Mcf)

 

40,834

 

 

19,084

 

 

114

%

Total (Boe)

 

34,965

 

 

21,046

 

 

66

%

 

 

 

 

 

 

Average Sales Prices:

 

 

 

 

 

Oil (per Bbl)

$

54.56

 

$

62.20

 

 

(12

)%

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

 

1.85

 

 

(7.55

)

 

 

Oil Net of Settled Derivatives (per Bbl)

 

56.41

 

 

54.65

 

 

3

%

Natural Gas and NGLs (per Mcf)

 

2.70

 

 

4.61

 

 

(41

)%

Realized Price on a Boe Basis Including all Realized Derivative Settlements

 

48.58

 

 

50.58

 

 

(4

)%

 

 

 

 

 

 

Costs and Expenses (per Boe):

 

 

 

 

 

Production Expenses

$

8.21

 

$

7.60

 

 

8

%

Production Taxes

 

4.41

 

 

5.29

 

 

(17

)%

General and Administrative Expense

 

1.65

 

 

1.70

 

 

(3

)%

Depletion, Depreciation, Amortization and Accretion

 

14.49

 

 

11.80

 

 

23

%

 

 

 

 

 

 

Net Producing Wells at Period End

 

340.6

 

 

248.3

 

 

37

%

Second Quarter Discretionary Capital Summary (in millions):

Q2 2019

Senior Note Repurchases

$10.5

Ground Game Acquisition Capital

$8.0

Ground Game D&C Capital

$14.0

Total

$32.5

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 June 30, 2019.

Crude Oil Derivative Swaps

Contract Period

 

Volume (Bbls)

 

Weighted Average Price (per Bbl)

2019:

 

 

 

 

3Q

 

2,430,444

 

$61.89

4Q

 

2,460,411

 

$62.01

2020:

 

 

 

 

1Q

 

2,476,456

 

$59.16

2Q

 

2,390,828

 

$58.48

3Q

 

2,340,348

 

$58.48

4Q

 

2,165,362

 

$58.00

2021:

 

 

 

 

1Q

 

1,375,050

 

$57.09

2Q

 

1,269,458

 

$57.75

3Q

 

636,410

 

$53.64

4Q

 

627,506

 

$53.67

2022:

 

 

 

 

1Q

 

453,780

 

$53.07

2Q

 

312,280

 

$52.30

3Q

 

306,576

 

$52.33

4Q

 

300,230

 

$52.35

Crude Oil Derivative Basis Swaps(1)

Contract Period

 

Total Volumes (Bbls)

 

Weighted Average Differential
($/Bbl)

07/01/2019 - 12/31/2019

 

1,840,000

 

($2.41)

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

LIQUIDITY

As of June 30, 2019, Northern had $2.8 million in cash, $31.0 million in a restricted acquisition deposit, and $173.0 million outstanding on its revolving credit facility. Northern had total liquidity of $254.8 million as of June 30, 2019, consisting of cash and borrowing availability under the revolving credit facility. Northern repurchased $10.1 million in principal amount of its Senior Notes in the second quarter, offset partially by $1.7 million for the final anticipated PIK interest payment. The total amount of Senior Notes outstanding was $688.5 million as of June 30, 2019. Net of cash and the restricted acquisition deposit, Northern’s total debt was reduced by $12.2 million from the prior quarter.

CAPITAL EXPENDITURES & DRILLING ACTIVITY

(in millions, except for net well data)

 

Three Months Ended June 30, 2019

Capital Expenditures Incurred:

 

 

Organic Drilling and Development Capital Expenditures

 

$

71.9

Ground Game Acquisition Capital Expenditures

 

$

8.0

Ground Game Drilling and Development Capital Expenditures

 

$

14.0

Acquisition of Oil and Natural Gas Properties and Other

 

$

4.0

 

 

 

Net Wells Added to Production

 

8.1

 

 

 

Net Producing Wells (Period-End)

 

340.6

 

 

 

Net Wells in Process (Period-End)

 

25.0

Increase in Wells in Process over 2018 Year-End

 

2.2

 

 

 

Weighted Average AFE for Wells Elected to During the Second Quarter

 

$

7.7

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

 

$

8.0

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 2.2 well increase in net wells in process during the six months ended June 30, 2019 are reflected in the amounts incurred year-to-date for drilling and development capital expenditures.

ACREAGE

As of June 30, 2019, Northern controlled leasehold of approximately 163,558 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.

SECOND 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 Friday, August 2, 2019 at 11:00 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: 13692790 - Northern Oil and Gas, Inc. Second Quarter 2019 Conference Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13692790 - Replay will be available through August 9, 2019

UPCOMING CONFERENCE SCHEDULE

EnerCom’s The Oil & Gas Conference
August 12 - 13, 2019, Denver, CO

8th Annual Intellisight Conference
August 14, 2019, Minneapolis, MN

Seaport Global Energy & Industrials Conference
August 27 - 28, 2019, Chicago, IL

2019 Midwest IDEAS Investor Conference
August 28 - 29, 2019, Chicago IL

Johnson Rice & Company 2019 Energy Conference
September 23- 29, 2019, New Orleans, LA

Friess Associates Research Round-Up
October 3, 2019, Jackson WY

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 and any properties pending acquisition, 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 consummate any pending acquisition transactions, other risks and uncertainties related to the closing of pending acquisition transactions, 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

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019 AND 2018

(UNAUDITED)

   

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

(In thousands, except share and per share data)

 

2019

 

2018

 

2019

 

2018

REVENUES

 

 

 

 

 

 

 

 

Oil and Gas Sales

 

$

149,847

 

 

$

109,047

 

 

$

282,530

 

 

$

195,928

 

Gain (Loss) on Derivative Instruments, Net

 

 

36,591

 

 

 

(42,203

)

 

 

(103,031

)

 

 

(62,474

)

Other Revenue

 

 

2

 

 

 

2

 

 

 

7

 

 

 

5

 

Total Revenues

 

 

186,440

 

 

 

66,846

 

 

 

179,506

 

 

 

133,459

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

Production Expenses

 

 

26,132

 

 

 

14,549

 

 

 

50,799

 

 

 

27,037

 

Production Taxes

 

 

14,034

 

 

 

10,132

 

 

 

26,553

 

 

 

18,054

 

General and Administrative Expenses

 

 

5,250

 

 

 

3,251

 

 

 

11,300

 

 

 

4,918

 

Depletion, Depreciation, Amortization and Accretion

 

 

46,091

 

 

 

22,596

 

 

 

91,225

 

 

 

41,227

 

Impairment of Other Current Assets

 

 

2,694

 

 

 

 

2,694

 

 

Total Operating Expenses

 

 

94,200

 

 

 

50,528

 

 

 

182,571

 

 

 

91,236

 

 

 

 

 

 

 

 

 

 

INCOME (LOSS) FROM OPERATIONS

 

 

92,239

 

 

 

16,318

 

 

 

(3,065

)

 

 

42,223

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

Interest Expense, Net of Capitalization

 

 

(17,778

)

 

 

(22,403

)

 

 

(37,327

)

 

 

(45,510

)

Loss on the Extinguishment of Debt

 

 

(425

)

 

 

(90,833

)

 

 

(425

)

 

 

(90,833

)

Debt Exchange Derivative Gain/(Loss)

 

 

(4,873

)

 

 

 

1,413

 

 

Contingent Consideration Loss

 

 

(24,763

)

 

 

 

(23,371

)

 

Other Income (Expense)

 

 

(1

)

 

 

371

 

 

 

14

 

 

 

538

 

Total Other Income (Expense)

 

 

(47,840

)

 

 

(112,865

)

 

 

(59,697

)

 

 

(135,805

)

 

 

 

 

 

 

 

 

 

INCOME (LOSS) BEFORE INCOME TAXES

 

 

44,399

 

 

 

(96,547

)

 

 

(62,762

)

 

 

(93,582

)

 

 

 

 

 

 

 

 

 

INCOME TAX PROVISION (BENEFIT)

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS)

 

$

44,399

 

 

$

(96,547

)

 

$

(62,762

)

 

$

(93,582

)

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Basic

 

$

0.12

 

 

$

(0.49

)

 

$

(0.17

)

 

$

(0.71

)

Net Income (Loss) Per Common Share – Diluted

 

$

0.12

 

 

$

(0.49

)

 

$

(0.17

)

 

$

(0.71

)

Weighted Average Shares Outstanding – Basic

 

 

378,368,462

 

 

 

196,140,610

 

 

 

374,927,630

 

 

 

131,039,552

 

Weighted Average Shares Outstanding – Diluted

 

 

378,724,511

 

 

 

196,140,610

 

 

 

374,927,630

 

 

 

131,039,552

 

CONDENSED BALANCE SHEETS

JUNE 30, 2019 AND DECEMBER 31, 2018

   

(In thousands, except par value and share data)

 

June 30, 2019

 

December 31, 2018

ASSETS

 

(Unaudited)

 

 

Current Assets:

 

 

 

 

Cash and Cash Equivalents

 

$

2,794

 

 

$

2,358

 

Accounts Receivable, Net

 

 

87,697

 

 

 

96,353

 

Advances to Operators

 

 

1,425

 

 

 

268

 

Prepaid Expenses and Other

 

 

8,226

 

 

 

12,360

 

Derivative Instruments

 

 

32,531

 

 

 

115,870

 

Income Tax Receivable

 

 

395

 

 

 

1,205

 

Total Current Assets

 

 

133,068

 

 

 

228,415

 

 

 

 

 

 

Property and Equipment:

 

 

 

 

Oil and Natural Gas Properties, Full Cost Method of Accounting

 

 

 

 

Proved

 

 

3,607,214

 

 

 

3,431,428

 

Unproved

 

 

9,249

 

 

 

4,307

 

Other Property and Equipment

 

 

1,609

 

 

 

998

 

Total Property and Equipment

 

 

3,618,072

 

 

 

3,436,732

 

Less – Accumulated Depreciation, Depletion and Impairment

 

 

(2,324,790

)

 

 

(2,233,987

)

Total Property and Equipment, Net

 

 

1,293,282

 

 

 

1,202,745

 

 

 

 

 

 

Derivative Instruments

 

 

26,610

 

 

 

61,843

 

Deferred Income Taxes

 

 

420

 

 

 

420

 

Acquisition Deposit

 

 

31,000

 

 

Other Noncurrent Assets, Net

 

 

10,012

 

 

 

10,223

 

 

 

 

 

 

Total Assets

 

$

1,494,391

 

 

$

1,503,645

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:

 

 

 

 

Accounts Payable

 

$

175,164

 

 

$

135,483

 

Accrued Expenses

 

 

2,070

 

 

 

2,769

 

Accrued Interest

 

 

15,050

 

 

 

16,468

 

Debt Exchange Derivative

 

 

2,791

 

 

 

18,183

 

Derivative Instruments

 

 

95

 

 

Contingent Consideration

 

 

36,992

 

 

 

58,069

 

Other Current Liabilities

 

 

566

 

 

 

555

 

Total Current Liabilities

 

 

232,726

 

 

 

231,526

 

 

 

 

 

 

Long-term Debt, Net

 

 

857,198

 

 

 

830,203

 

Derivative Instruments

 

 

1,644

 

 

Asset Retirement Obligations

 

 

12,845

 

 

 

11,946

 

Other Noncurrent Liabilities

 

 

329

 

 

 

105

 

 

 

 

 

 

TOTAL LIABILITIES

 

$

1,104,742

 

 

$

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;
389,435,991 Shares Outstanding at 6/30/2019
378,333,070 Shares Outstanding at 12/31/2018

 

 

389

 

 

 

378

 

Additional Paid-In Capital

 

 

1,248,906

 

 

 

1,226,371

 

Retained Deficit

 

 

(859,647

)

 

 

(796,884

)

Total Stockholders’ Equity

 

 

389,649

 

 

 

429,865

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

1,494,391

 

 

$

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 June 30,

 

Six Months Ended June 30,

(In thousands, except share and per share data)

 

2019

 

2018

 

2019

 

2018

Net Income (Loss)

 

$

44,399

 

 

$

(96,547

)

 

$

(62,762

)

 

$

(93,582

)

Add:

 

 

 

 

 

 

 

 

Impact of Selected Items:

 

 

 

 

 

 

 

 

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

 

 

(31,857

)

 

 

29,936

 

 

 

120,311

 

 

 

42,077

 

Impairment of Other Current Assets

 

 

2,694

 

 

 

 

2,694

 

 

Loss on the Extinguishment of Debt

 

 

425

 

 

 

90,833

 

 

 

425

 

 

 

90,833

 

Debt Exchange Derivative (Gain) Loss

 

 

4,873

 

 

 

 

(1,413

)

 

Contingent Consideration (Gain) Loss

 

 

24,763

 

 

 

 

23,371

 

 

Acquisition Transaction Costs

 

 

513

 

 

 

 

513

 

 

Selected Items, Before Income Taxes

 

 

1,411

 

 

 

120,769

 

 

 

145,901

 

 

 

132,910

 

Income Tax of Selected Items(1)

 

 

(346

)

 

 

(6,180

)

 

 

(20,696

)

 

 

(9,912

)

Selected Items, Net of Income Taxes

 

$

1,065

 

 

$

114,589

 

 

$

125,205

 

 

$

122,998

 

 

 

 

 

 

 

 

 

 

Adjusted Net Income

 

$

45,465

 

 

$

18,042

 

 

$

62,443

 

 

$

29,417

 

 

 

 

 

 

 

 

 

 

Weighted Average Shares Outstanding – Basic

 

 

378,368,462

 

 

 

196,140,610

 

 

 

374,927,630

 

 

 

131,039,552

 

Weighted Average Shares Outstanding – Diluted

 

 

378,724,511

 

 

 

196,413,013

 

 

 

375,736,820

 

 

 

131,248,726

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Basic

 

$

0.12

 

 

$

(0.49

)

 

$

(0.17

)

 

$

(0.71

)

Add:

 

 

 

 

 

 

 

 

Impact of Selected Items, Net of Income Taxes

 

 

 

0.58

 

 

 

0.33

 

 

 

0.93

 

Adjusted Net Income Per Common Share – Basic

 

$

0.12

 

 

$

0.09

 

 

$

0.16

 

 

$

0.22

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Diluted

 

$

0.12

 

 

$

(0.49

)

 

$

(0.17

)

 

$

(0.71

)

Add:

 

 

 

 

 

 

 

 

Impact of Selected Items, Net of Income Taxes

 

 

 

0.58

 

 

 

0.33

 

 

 

0.93

 

Adjusted Net Income Per Common Share – Diluted

 

$

0.12

 

 

$

0.09

 

 

$

0.16

 

 

$

0.22

 

  1. For the three months ended June 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, which does not include an adjustment for a change in valuation allowance. For the six months ended June 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, and includes a $15.1 million adjustment for an increase in valuation allowance. For the three and six months ended June 30, 2018, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $23.4 million and $22.7 million, respectively, for a reduction in valuation allowance.

Reconciliation of Adjusted EBITDA

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

(In thousands)

 

2019

 

2018

 

2019

 

2018

Net Income (Loss)

 

$

44,399

 

 

$

(96,547

)

 

$

(62,762

)

 

$

(93,582

)

Add:

 

 

 

 

 

 

 

 

Interest Expense

 

 

17,778

 

 

 

22,403

 

 

 

37,327

 

 

 

45,510

 

Income Tax Provision (Benefit)

 

 

 

 

Depreciation, Depletion, Amortization and Accretion

 

 

46,091

 

 

 

22,596

 

 

 

91,225

 

 

 

41,227

 

Impairment of Other Current Assets

 

 

2,694

 

 

 

 

2,694

 

 

Non-Cash Stock-Based Compensation

 

 

1,643

 

 

 

1,324

 

 

 

4,394

 

 

 

438

 

Loss on the Extinguishment of Debt

 

 

425

 

 

 

90,833

 

 

 

425

 

 

 

90,833

 

Debt Exchange Derivative (Gain) Loss

 

 

4,873

 

 

 

 

(1,413

)

 

Contingent Consideration (Gain) Loss

 

 

24,763

 

 

 

 

23,371

 

 

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

 

 

(31,857

)

 

 

29,936

 

 

 

120,311

 

 

 

42,077

 

Adjusted EBITDA

 

$

110,810

 

 

$

70,546

 

 

$

215,572

 

 

$

126,504

 

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