Northern Oil and Gas, Inc. Announces Second Quarter 2020 Results

HIGHLIGHTS

  • Total debt reduced by $52.2 million in the second quarter, resulting in over $3 million in interest savings per annum
  • Strong risk management drove realized commodity hedge gains of $77.4 million in the second quarter
  • Cash flow from operations totaled $53.1 million, excluding $48.5 million received from changes in working capital
  • Total capital expenditures were $34.5 million in the second quarter
  • Wells in process remain near record levels at 26.7 net wells
  • Production averaged 23,804 barrels of oil equivalent (“Boe”) per day, driven by material curtailments and shut-ins
  • Approximately 26,500 barrels per day of remaining 2020 oil hedged at over $58 per barrel (“Bbl”) average prices
  • Approximately 21,500 barrels per day of 2021 oil hedged at over $54.50 per Bbl average prices

MINNEAPOLIS--(BUSINESS WIRE)-- Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s second quarter results.

MANAGEMENT COMMENTS

“In one of the most challenging quarters for the oil industry in decades, Northern’s unique, actively managed working-interest business model continues to deliver,” commented Nick O’Grady, Northern’s Chief Executive Officer. “Hedges protected cash flows despite the turmoil, and capital spending reductions were instituted rapidly. We continued to reduce our debt levels, and carefully and methodically have added to our portfolio to build for future growth and returns.”

SECOND QUARTER FINANCIAL RESULTS

Second quarter Adjusted Net Income was $10.7 million or $0.02 per diluted share. Second quarter GAAP net loss was $899.2 million or $2.17 per diluted share, driven in large part by non-cash items: a $762.7 million impairment expense and a $150.1 million mark-to-market loss on unsettled commodity derivatives. Cash flow from operations was $53.1 million in the second quarter, excluding $48.5 million received from changes in working capital. Adjusted EBITDA in the second quarter was $66.1 million. (See “Non-GAAP Financial Measures” below.)

PRODUCTION

Second quarter production was 23,804 Boe per day. Oil production represented 77% of total production at 18,234 Bbls per day. Production declined due to decisions by many of Northern’s operating partners to shut-in or curtail production and defer development plans as a result of the low commodity price environment. Northern estimates that curtailments, shut-ins and delayed well completions reduced the Company’s average daily production by approximately 16,800 Boe per day in the second quarter. Northern had only 1.3 net wells turned online during the second quarter, compared to 7.3 net wells turned online in the first quarter of 2020.

PRICING

During the second quarter, NYMEX West Texas Intermediate (“WTI”) crude oil averaged $27.95 per Bbl, and NYMEX natural gas at Henry Hub averaged $1.70 per million cubic feet (“Mcf”). Northern’s unhedged net realized oil price in the second quarter was $17.35, representing a $10.60 differential to WTI prices. Oil differentials were extremely wide in the month of May, but improved significantly in June. Northern’s second quarter unhedged net realized gas price was $(2.67) per Mcf, representing approximately (157)% realizations compared with Henry Hub pricing. The dislocation in natural gas and NGL prices was due to physical storage constraints, which created negative pricing for NGL products as demand collapsed due primarily to the COVID-19 pandemic. Higher compression, gathering, and processing charges that were in excess of natural gas and NGL sales prices additionally contributed to negative realized pricing.

OPERATING COSTS

Lease operating costs were $26.6 million in the second quarter of 2020 compared to $37.3 million in the first quarter of 2020 driven by a 46% reduction in production volumes, partially offset by increased processing and salt water disposal costs. Northern expects further cost reductions will be realized in the third quarter. Second quarter general and administrative (“G&A”) costs totaled $4.7 million, which includes non-cash stock-based compensation. Cash G&A expense totaled $3.5 million or $1.61 per Boe in the second quarter versus $3.8 million in the first quarter of 2020, primarily due to lower professional fees.

CAPITAL EXPENDITURES AND ACQUISITIONS

Capital spending for the second quarter was $34.5 million, made up of $32.7 million of organic D&C capital and $1.8 million of total acquisition spending and other, inclusive of ground game D&C spending. As mentioned above, Northern added 1.3 net wells to production in the second quarter, and wells in process ended at 26.7 net wells. On the ground game acquisition front, Northern closed on three transactions during the second quarter totaling 0.2 net wells and 124 net mineral acres.

Northern has previously announced several third quarter acquisitions. Subsequent to the closing of the second quarter, Northern has agreed to acquire or acquired 0.7 net producing wells, 3.9 net wells in process, and approximately 763 net acres for a total consideration of $4.6 million and 2.95 million shares of common stock, with an additional 0.45 million shares contingent on continued operation of the Dakota Access Pipeline. Pro forma for the closing of these transactions, Northern anticipates wells in process as of July 31, 2020, to total 30.3 net wells. Year to date, Northern’s ground game acquisitions that have been committed to or closed have contributed a total of 8.4 net wells that are either producing or in process, and added 1,852 net acres.

LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2020, Northern had $1.8 million in cash and $568.0 million outstanding on its revolving credit facility. As previously announced, Northern completed a semi-annual borrowing base redetermination under its revolving credit facility on July 8, 2020, with the borrowing base set at $660.0 million. Pro forma for the new borrowing base, Northern had total liquidity of $93.8 million as of June 30, 2020, consisting of cash and borrowing availability under the revolving credit facility.

As of June 30, 2020, Northern had additional debt outstanding consisting of a $130.0 million 6% Senior Unsecured Note and $297.3 million of 8.5% Senior Secured Notes. During the second quarter, Northern strengthened its balance sheet through several agreements with noteholders, which resulted in $30.2 million in principal amount of the 8.5% Senior Secured Notes being retired.

Since the end of the second quarter, Northern has entered into additional agreements that, when closed, will reduce the principal amount of the 8.5% Senior Secured Notes by an additional $4.0 million and reduce the liquidation value of its outstanding Preferred Stock by $7.6 million.

2020 GUIDANCE

 

3Q:20

 

4Q:20

Production (Boe/day)

22,500 - 30,000

 

30,000 - 40,000

Capital Expenditures (2H:20)

$50 - $75 million

Northern is beginning to see a slow but steady return of curtailed and shut-in production to sales since the end of the second quarter. Northern projects production of 22,500 - 30,000 Boe per day in the third quarter and 30,000 - 40,000 Boe per day in the fourth quarter. Total capital expenditures are currently expected to be approximately $50 - 75 million in the second half of 2020, inclusive of ground game and acquisitions. This guidance assumes only 3.6 net wells turned in line in the second half of 2020. Northern reiterates its previous guidance for total 2020 capital spending of $175 - 200 million, with a reserve completion budget of $50 million.

2021 COMMENTARY

Looking out to 2021, Northern expects to benefit from carrying a near record number of wells in process (“WIP”). As of July 31, 2020, Northern had 28.6 net WIPs including approximately 6 net wells completed but not turned in line, and management projects its WIP count to exceed 30 net wells by year-end 2020. Northern’s ability as a non-operator to continue to build high quality inventory, despite an 80% reduction in the Williston rig count, is a testament to the active management of its capital development program.

Northern’s base case for 2021 presupposes that production curtailments will continue to subside and that completion activity will steadily increase starting late in the fourth quarter of 2020. Under this scenario, Northern expects to see production approaching 40,000 Boe per day by early 2021, nearing volume levels seen in early 2020. Furthermore, given the Company’s continued success on the ground game front, which continues to build the number of wells in process to near record levels, Northern forecasts that this level of production should be maintained throughout the remainder of 2021 on a capital budget of approximately $190 - 240 million. Under this scenario, Northern sees both Adjusted EBITDA and free cash flow at similar or higher levels to 2020, despite lower hedge values at recent strip prices.

Given the volatility in the sector, significant uncertainty remains and actual results will be driven by the timing of curtailments and shut-ins returning to sales, completed wells turned to sales and wells in process being completed and producing. Northern’s downside case, which assumes a slower WIP completion pace and little new drilling activity, would be expected to drive $40 - $60 million of lower capital spending but still generate production in excess of 35,000 Boe per day for 2021.

SECOND QUARTER 2020 RESULTS

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

 

 

Three Months Ended June 30,

 

 

2020

 

2019

 

% Change

Net Production:

 

 

 

 

 

 

Oil (Bbl)

 

1,659,293

 

 

2,562,513

 

 

(35)

%

Natural Gas and NGLs (Mcf)

 

3,041,418

 

 

3,715,936

 

 

(18)

%

Total (Boe)

 

2,166,196

 

 

3,181,835

 

 

(32)

%

 

 

 

 

 

 

 

Average Daily Production:

 

 

 

 

 

 

Oil (Bbl)

 

18,234

 

 

28,159

 

 

(35)

%

Natural Gas and NGLs (Mcf)

 

33,422

 

 

40,834

 

 

(18)

%

Total (Boe)

 

23,804

 

 

34,965

 

 

(32)

%

 

 

 

 

 

 

 

Average Sales Prices:

 

 

 

 

 

 

Oil (per Bbl)

 

$

17.35

 

 

$

54.56

 

 

(68)

%

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

 

46.19

 

 

1.85

 

 

 

Oil Net of Settled Oil Derivatives (per Bbl)

 

63.54

 

 

56.41

 

 

13

%

 

 

 

 

 

 

 

Natural Gas and NGLs (per Mcf)

 

(2.67)

 

 

2.70

 

 

 

Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf)

 

0.26

 

 

 

 

 

Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf)

 

(2.41)

 

 

2.70

 

 

 

 

 

 

 

 

 

 

Realized Price on a Boe Basis Excluding Settled Commodity Derivatives

 

9.54

 

 

47.09

 

 

(80)

%

Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe)

 

35.75

 

 

1.49

 

 

 

Realized Price on a Boe Basis Including Settled Commodity Derivatives

 

45.29

 

 

48.58

 

 

(7)

%

 

 

 

 

 

 

 

Costs and Expenses (per Boe):

 

 

 

 

 

 

Production Expenses

 

$

12.30

 

 

$

8.21

 

 

50

%

Production Taxes

 

0.89

 

 

4.41

 

 

(80)

%

General and Administrative Expenses

 

2.17

 

 

1.65

 

 

32

%

Depletion, Depreciation, Amortization and Accretion

 

16.97

 

 

14.49

 

 

17

%

 

 

 

 

 

 

 

Net Producing Wells at Period End

 

466.0

 

 

340.6

 

 

37

%

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 table summarizes Northern’s open crude oil commodity derivative contracts scheduled to settle after June 30, 2020.

Crude Oil Commodity Derivative Swaps(1)

Contract Period

 

Volume (Bbls)

 

Volume (Bbls/Day)

 

Weighted Average Price (per Bbl)

2020:

 

 

 

 

 

 

3Q

 

2,501,348

 

27,189

 

$58.47

4Q

 

2,372,362

 

25,787

 

$58.03

2021:

 

 

 

 

 

 

1Q

 

2,201,250

 

24,458

 

$55.53

2Q

 

1,997,458

 

21,950

 

$55.88

3Q

 

1,809,410

 

19,668

 

$53.46

4Q

 

1,800,506

 

19,571

 

$53.47

_____________

(1)

 

This table does not reflect additional potential hedged volumes under “swaption” contracts, which are crude oil derivative contracts entered into by Northern that give counterparties the option to extend certain current derivative contracts for additional periods. Based on current pricing, none of these swaptions would be expected to be exercised.

The following table summarizes Northern’s open natural gas commodity derivative contracts scheduled to settle after June 30, 2020.

Natural Gas Commodity Derivative Swaps

Contract Period

 

Gas (MMBTU)

 

Volume (MMBTU/Day)

 

Weighted Average Price (per Mcf)

2020:

 

 

 

 

 

 

3Q

 

1,610,000

 

17,500

 

$2.35

4Q

 

1,610,000

 

17,500

 

$2.35

2021:

 

 

 

 

 

 

1Q

 

2,700,000

 

30,000

 

$2.43

2Q

 

2,275,000

 

25,000

 

$2.43

3Q

 

2,300,000

 

25,000

 

$2.43

4Q

 

2,300,000

 

25,000

 

$2.43

CAPITAL EXPENDITURES & DRILLING ACTIVITY

(In millions, except for net well data)

 

Three Months Ended
June 30, 2020

 

Six Months Ended
June 30, 2020

Capital Expenditures Incurred:

 

 

 

 

Organic Drilling and Development Capital Expenditures

 

$

32.7

 

 

$

97.5

 

Ground Game Drilling and Development Capital Expenditures

 

$

0.3

 

 

$

14.3

 

Ground Game Acquisition Capital Expenditures

 

$

0.3

 

 

$

7.5

 

Other

 

$

1.1

 

 

$

1.9

 

 

 

 

 

 

Net Wells Added to Production

 

1.3

 

 

8.6

 

 

 

 

 

 

Net Producing Wells (Period-End)

 

 

 

466.0

 

 

 

 

 

 

Net Wells in Process (Period-End)

 

 

 

26.7

 

Increase in Wells in Process over Prior Period

 

(0.5)

 

 

0.9

 

 

 

 

 

 

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

 

$7.7 million

 

$7.6 million

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 increase of 0.9 in net wells in process during the six months ended June 30, 2020 are reflected in the amounts incurred year-to-date for drilling and development capital expenditures.

ACREAGE

As of June 30, 2020, Northern controlled leasehold of approximately 182,899 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 2020 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 7, 2020 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:

Website: https://78449.themediaframe.com/dataconf/productusers/nog/mediaframe/39975/indexl.html
Dial-In Number: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13707746 - Northern Oil and Gas, Inc. Second Quarter 2020 Earnings Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13707746 - Replay will be available through August 14, 2020

UPCOMING CONFERENCE SCHEDULE

CFA Society Minnesota Intellisight Investor Day
August 12, 2020

Enercom Oil and Gas Conference
August 17, 2020

Seaport Global Summer Investor Conference
August 26, 2020

ABOUT NORTHERN OIL AND GAS

Northern Oil and Gas, Inc. is a company with a primary strategy of investing in non-operated minority working and mineral interests in oil & gas properties, 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, operating and financial performance, 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: the effects of the COVID-19 pandemic and related economic slowdown, 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, ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline, Northern’s ability to acquire additional development opportunities, Northern’s ability to consummate any pending acquisition transactions, other risks and uncertainties related to the closing of pending acquisition transactions, 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, health-related epidemics, 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
June 30,

 

Six Months Ended
June 30,

(In thousands, except share and per share data)

 

2020

 

2019

 

2020

 

2019

Revenues

 

 

 

 

 

 

 

 

Oil and Gas Sales

 

$

20,664

 

 

$

149,847

 

 

$

150,860

 

 

$

282,530

 

Gain (Loss) on Commodity Derivatives, Net

 

(72,638)

 

 

36,591

 

 

303,943

 

 

(103,031)

 

Other Revenue

 

3

 

 

2

 

 

12

 

 

7

 

Total Revenues

 

(51,971)

 

 

186,440

 

 

454,815

 

 

179,506

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

 

Production Expenses

 

26,638

 

 

26,132

 

 

63,974

 

 

50,799

 

Production Taxes

 

1,917

 

 

14,034

 

 

13,813

 

 

26,553

 

General and Administrative Expense

 

4,710

 

 

5,250

 

 

9,580

 

 

11,300

 

Depletion, Depreciation, Amortization and Accretion

 

36,756

 

 

46,091

 

 

98,565

 

 

91,225

 

Impairment of Other Current Assets

 

 

 

2,694

 

 

 

 

2,694

 

Impairment Expense

 

762,716

 

 

 

 

762,716

 

 

 

Total Operating Expenses

 

832,737

 

 

94,200

 

 

948,648

 

 

182,571

 

 

 

 

 

 

 

 

 

 

Income (Loss) From Operations

 

(884,708)

 

 

92,239

 

 

(493,833)

 

 

(3,065)

 

 

 

 

 

 

 

 

 

 

Other Income (Expense)

 

 

 

 

 

 

 

 

Interest Expense, Net of Capitalization

 

(13,957)

 

 

(17,778)

 

 

(30,508)

 

 

(37,327)

 

Loss on Unsettled Interest Rate Derivatives, Net

 

(752)

 

 

 

 

(1,429)

 

 

 

Gain (Loss) on Extinguishment of Debt, Net

 

217

 

 

(425)

 

 

(5,310)

 

 

(425)

 

Debt Exchange Derivative Gain/(Loss)

 

 

 

(4,873)

 

 

 

 

1,413

 

Contingent Consideration Loss

 

 

 

(24,763)

 

 

 

 

(23,371)

 

Other Income (Expense)

 

 

 

(1)

 

 

 

 

14

 

Total Other Income (Expense)

 

(14,492)

 

 

(47,840)

 

 

(37,247)

 

 

(59,696)

 

 

 

 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

 

(899,200)

 

 

44,399

 

 

(531,080)

 

 

(62,762)

 

 

 

 

 

 

 

 

 

 

Income Tax Provision (Benefit)

 

 

 

 

 

(166)

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss)

 

$

(899,200)

 

 

$

44,399

 

 

$

(530,914)

 

 

$

(62,762)

 

 

 

 

 

 

 

 

 

 

Cumulative Preferred Stock Dividend

 

(3,788)

 

 

 

 

(7,517)

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Attributable to Common Shareholders

 

$

(902,988)

 

 

$

44,399

 

 

$

(538,431)

 

 

$

(62,762)

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Basic

 

$

(2.17)

 

 

$

0.12

 

 

$

(1.31)

 

 

$

(0.17)

 

Net Income (Loss) Per Common Share – Diluted

 

$

(2.17)

 

 

$

0.12

 

 

$

(1.31)

 

 

$

(0.17)

 

Weighted Average Common Shares Outstanding – Basic

 

415,356,043

 

 

378,368,462

 

 

409,509,292

 

 

374,927,630

 

Weighted Average Common Shares Outstanding – Diluted

 

415,356,043

 

 

378,724,511

 

 

409,509,292

 

 

374,927,630

 

 

CONDENSED BALANCE SHEETS

(In thousands, except par value and share data)

 

June 30, 2020

 

December 31, 2019

Assets

 

(Unaudited)

 

 

Current Assets:

 

 

 

 

Cash and Cash Equivalents

 

$

1,838

 

 

$

16,068

 

Accounts Receivable, Net

 

43,408

 

 

108,274

 

Advances to Operators

 

788

 

 

893

 

Prepaid Expenses and Other

 

2,204

 

 

1,964

 

Derivative Instruments

 

156,436

 

 

5,628

 

Income Tax Receivable

 

420

 

 

210

 

Total Current Assets

 

205,094

 

 

133,037

 

 

 

 

 

 

Property and Equipment:

 

 

 

 

Oil and Natural Gas Properties, Full Cost Method of Accounting

 

 

 

 

Proved

 

4,300,151

 

 

4,178,605

 

Unproved

 

10,681

 

 

11,047

 

Other Property and Equipment

 

2,164

 

 

2,157

 

Total Property and Equipment

 

4,312,996

 

 

4,191,809

 

Less – Accumulated Depreciation, Depletion and Impairment

 

(3,303,913)

 

 

(2,443,216)

 

Total Property and Equipment, Net

 

1,009,083

 

 

1,748,593

 

 

 

 

 

 

Derivative Instruments

 

34,566

 

 

8,554

 

Deferred Income Taxes

 

 

 

210

 

Acquisition Deposit

 

774

 

 

 

Other Noncurrent Assets, Net

 

13,756

 

 

15,071

 

 

 

 

 

 

Total Assets

 

$

1,263,273

 

 

$

1,905,465

 

 

 

 

 

 

Liabilities and Stockholders' Equity

Current Liabilities:

 

 

 

 

Accounts Payable

 

$

50,005

 

 

$

69,395

 

Accrued Liabilities

 

54,216

 

 

110,374

 

Accrued Interest

 

7,895

 

 

11,615

 

Derivative Instruments

 

1,198

 

 

11,298

 

Current Portion of Long-term Debt

 

65,000

 

 

 

Other Current Liabilities

 

906

 

 

795

 

Total Current Liabilities

 

179,220

 

 

203,477

 

 

 

 

 

 

Long-term Debt

 

924,171

 

 

1,118,161

 

Derivative Instruments

 

1,428

 

 

8,079

 

Asset Retirement Obligations

 

17,526

 

 

16,759

 

Other Noncurrent Liabilities

 

199

 

 

345

 

 

 

 

 

 

Total Liabilities

 

$

1,122,544

 

 

$

1,346,822

 

 

 

 

 

 

Commitments and Contingencies (Note 8)

 

 

 

 

 

 

 

 

 

Stockholders’ Equity

 

 

 

 

Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized;

2,294,702 Series A Shares Outstanding at 6/30/2020

1,500,000 Series A Shares Outstanding at 12/31/2019

 

2

 

 

2

 

Common Stock, Par Value $.001; 675,000,000 Shares Authorized;

436,439,915 Shares Outstanding at 6/30/2020

406,085,183 Shares Outstanding at 12/31/2019

 

436

 

 

406

 

Additional Paid-In Capital

 

1,544,407

 

 

1,431,438

 

Retained Deficit

 

(1,404,117)

 

 

(873,203)

 

Total Stockholders’ Equity

 

140,729

 

 

558,643

 

Total Liabilities and Stockholders’ Equity

 

$

1,263,273

 

 

$

1,905,465

 

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 unsettled commodity derivatives, net of tax, (ii) (gain) loss on extinguishment of debt, net of tax, (iii) debt exchange derivative (gain) loss, net of tax, (iv) contingent consideration loss, net of tax, (v) acquisition transaction costs, net of tax, (vi) impairment of other current assets, net of tax, (vii) impairment expense, net of tax, and (viii) loss on unsettled interest rate derivatives, 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) non-cash stock-based compensation expense, (v) (gain) loss on extinguishment of debt, (vi) debt exchange derivative (gain) loss, (vii) contingent consideration loss, (viii) (gain) loss on unsettled commodity derivatives, (ix) loss on unsettled interest rate derivatives, (x) impairment of other current assets, and (xi) impairment expense. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below. Where references are pro forma, forward-looking or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. Northern could not provide such reconciliation without undue hardship because such Adjusted EBITDA numbers are estimations, approximations and/or ranges. In addition, it would be difficult for Northern to present a detailed reconciliation on account of many unknown variables for the reconciling items, including without limitation future income taxes, full-cost ceiling impairments, and unrealized gains or losses on commodity derivatives. For the same reasons, Northern is unable to address the probable significance of the unavailable information, which could be material to future results.

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)

 

2020

 

2019

 

2020

 

2019

Net Income (Loss)

 

$

(899,200)

 

 

$

44,399

 

 

$

(530,914)

 

 

$

(62,762)

 

Add:

 

 

 

 

 

 

 

 

Impact of Selected Items:

 

 

 

 

 

 

 

 

(Gain) Loss on Unsettled Commodity Derivatives

 

150,077

 

 

(31,857)

 

 

(194,999)

 

 

120,311

 

Impairment of Other Current Assets

 

 

 

2,694

 

 

 

 

2,694

 

(Gain) Loss on Extinguishment of Debt

 

(217)

 

 

425

 

 

5,310

 

 

425

 

Debt Exchange Derivative (Gain) Loss

 

 

 

4,873

 

 

 

 

(1,413)

 

Contingent Consideration Loss

 

 

 

24,763

 

 

 

 

23,371

 

Acquisition Transaction Costs

 

 

 

513

 

 

 

 

513

 

Loss on Unsettled Interest Rate Derivatives

 

752

 

 

 

 

1,429

 

 

 

Impairment Expense

 

762,716

 

 

 

 

762,716

 

 

 

Selected Items, Before Income Taxes

 

913,328

 

 

1,411

 

 

574,456

 

 

145,901

 

Income Tax of Selected Items(1)

 

(3,461)

 

 

(346)

 

 

(10,668)

 

 

(20,696)

 

Selected Items, Net of Income Taxes

 

909,866

 

 

1,065

 

 

563,788

 

 

125,205

 

 

 

 

 

 

 

 

 

 

Adjusted Net Income

 

$

10,667

 

 

$

45,465

 

 

$

32,874

 

 

$

62,443

 

 

 

 

 

 

 

 

 

 

Weighted Average Shares Outstanding – Basic

 

415,356,043

 

 

378,368,462

 

 

409,509,292

 

 

374,927,630

 

Weighted Average Shares Outstanding – Diluted

 

515,569,721

 

 

378,724,511

 

 

509,897,841

 

 

375,736,820

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Basic

 

$

(2.16)

 

 

$

0.12

 

 

$

(1.30)

 

 

$

(0.17)

 

Add:

 

 

 

 

 

 

 

 

Impact of Selected Items, Net of Income Taxes

 

2.19

 

 

 

 

1.38

 

 

0.33

 

Adjusted Net Income Per Common Share – Basic

 

$

0.03

 

 

$

0.12

 

 

$

0.08

 

 

$

0.16

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Diluted

 

$

(1.74)

 

 

$

0.12

 

 

$

(1.04)

 

 

$

(0.17)

 

Add:

 

 

 

 

 

 

 

 

Impact of Selected Items, Net of Income Taxes

 

1.76

 

 

 

 

1.10

 

 

0.33

 

Adjusted Net Income Per Common Share – Diluted

 

$

0.02

 

 

$

0.12

 

 

$

0.06

 

 

$

0.16

 

______________

(1)

 

For the three and six months ended June 30, 2020, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $220.3 million and $130.1 million, respectively, for a change in valuation allowance. 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 a change in valuation allowance.

Reconciliation of Adjusted EBITDA

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

(In thousands)

 

2020

 

2019

 

2020

 

2019

Net Income (Loss)

 

$

(899,200)

 

 

$

44,399

 

 

$

(530,914)

 

 

$

(62,762)

 

Add:

 

 

 

 

 

 

 

 

Interest Expense

 

13,957

 

 

17,778

 

 

30,508

 

 

37,327

 

Income Tax Provision (Benefit)

 

 

 

 

 

(166)

 

 

 

Depreciation, Depletion, Amortization and Accretion

 

36,756

 

 

46,091

 

 

98,565

 

 

91,225

 

Impairment of Other Current Assets

 

 

 

2,694

 

 

 

 

2,694

 

Non-Cash Stock-Based Compensation

 

1,214

 

 

1,643

 

 

2,293

 

 

4,394

 

(Gain) Loss on Extinguishment of Debt

 

(217)

 

 

425

 

 

5,310

 

 

425

 

Debt Exchange Derivative (Gain) Loss

 

 

 

4,873

 

 

 

 

(1,413)

 

Contingent Consideration Loss

 

 

 

24,763

 

 

 

 

23,371

 

Loss on Unsettled Interest Rate Derivatives

 

752

 

 

 

 

1,429

 

 

 

(Gain) Loss on Unsettled Commodity Derivatives

 

150,077

 

 

(31,857)

 

 

(194,999)

 

 

120,311

 

Impairment Expense

 

762,716

 

 

 

 

762,716

 

 

 

Adjusted EBITDA

 

$

66,055

 

 

$

110,810

 

 

$

174,742

 

 

$

215,572

 

 

Mike Kelly, CFA
EVP Finance
952-476-9800
mkelly@northernoil.com

Source: Northern Oil and Gas, Inc.