Northern Oil and Gas, Inc. Announces Third Quarter 2021 Results and Updates Guidance

HIGHLIGHTS

  • Third quarter total production of 57,647 Boe per day, up 98% from the third quarter of 2020
  • Oil production of 34,035 Bbl per day, up 52% from the third quarter of 2020
  • Third quarter GAAP cash flow from operations of $94.4 million. Excluding changes in net working capital, cash flow from operations was $122.3 million, up 253% from the third quarter of 2020
  • Total capital expenditures of $63.2 million during the third quarter, excluding the closing of our previously-announced Permian acquisition on August 2, 2021
  • Free Cash Flow (non-GAAP) of $55.4 million, post-preferred stock dividends. See “Non-GAAP Financial Measures” below
  • Announced $154.0 million Williston Basin acquisition in October; closed on the acquisition of Permian Basin properties on August 2, 2021
  • Updated 2021 guidance includes increased annual production, reduced unit costs, reduced capital expenditures and improved pricing differentials

MINNEAPOLIS--(BUSINESS WIRE)-- Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s third quarter results and provided updated 2021 guidance.

MANAGEMENT COMMENTS

“The third quarter again demonstrated Northern’s stellar business execution,” commented Nick O’Grady, Northern’s Chief Executive Officer. “We delivered record free cash flow yet again and closed a significant Permian acquisition in the third quarter. In October, we announced the signing of another meaningfully accretive transaction, as we relentlessly seek to increase shareholder value. We see significant additional opportunities to further benefit shareholders and remain dedicated to building a diversified, low-leverage entity, with steadily increasing cash returns.”

THIRD QUARTER FINANCIAL RESULTS

Oil and natural gas sales for the third quarter were $259.7 million, up 15% over the second quarter. Third quarter GAAP net income, inclusive of a $71.8 million non-cash net mark-to-market loss on derivatives, was $12.6 million or $0.19 per diluted share. Third quarter Adjusted Net Income was $64.1 million or $0.84 per diluted share, which was reduced by $20.8 million (or $0.27 per diluted share) by the net deferred tax effect from adjustments primarily related to changes in the mark-to-market values of derivatives. Adjusted Net Income was up from $27.5 million or $0.51 per diluted share in the third quarter of 2020. Adjusted EBITDA in the third quarter was $136.1 million, up 65% from the third quarter of 2020. See “Non-GAAP Financial Measures” below.

PRODUCTION

Third quarter production was 57,647 Boe per day, a 6% increase from the second quarter of 2021 and a 98% increase from the third quarter of 2020. Oil represented 59% of total production in the third quarter. Oil production was 34,035 Bbl per day, a 2% increase over the second quarter of 2021 and a 52% increase over the third quarter of 2020. Northern had 6.5 net wells turned in-line during the third quarter, compared to 10.5 net wells turned in-line in the second quarter of 2021. Northern’s Marcellus production made up 21% of total volumes in the third quarter, and were up quarter-over-quarter with the first EQT-operated pad coming online. Northern’s Permian production made up 4% of volumes in the third quarter, reflecting a partial quarter impact from recently closed acquisitions, and are expected to ramp substantially in the fourth quarter.

PRICING

During the third quarter, NYMEX West Texas Intermediate (“WTI”) crude oil averaged $70.54 per Bbl, and NYMEX natural gas at Henry Hub averaged $4.31 per million cubic feet (“Mcf”). Northern’s unhedged net realized oil price in the third quarter was $64.91, representing a $5.63 differential to WTI prices. Northern’s unhedged net realized gas price in the third quarter was $4.33 per Mcf, representing approximately 100% realizations compared with Henry Hub pricing.

OPERATING COSTS

Lease operating costs were $43.2 million in the third quarter of 2021, or $8.15 per Boe, down over 5% on a per unit basis compared to the second quarter of 2021. The reduction in unit costs was driven by increased low-cost Marcellus and Permian production, partially offset by lower new completions and higher processing costs associated with strong NGL prices. Third quarter general and administrative (“G&A”) costs totaled $5.5 million or $1.04 per Boe. This includes $0.7 million of legal and other transaction expenses in connection with the Permian and Williston acquisitions and $0.7 million of non-cash stock-based compensation. Northern’s G&A costs excluding these amounts totaled $4.1 million or $0.78 per Boe in the third quarter, down 44% versus the third quarter in the prior year.

CAPITAL EXPENDITURES AND ACQUISITIONS

Capital spending for the third quarter was $63.2 million, down 8% from the second quarter of 2021. Spending was made up of $53.0 million of total drilling and completion (“D&C”) capital on organic and ground game assets, and $10.2 million of ground game acquisition spending and other items. These amounts exclude our unbudgeted acquisitions, such as the Permian acquisition that closed in August 2021. Our Williston Basin spending made up 73% of the total capital expenditures for the quarter, the Permian made up 20%, the Marcellus made up 5% and other items made up 2%. On the ground game acquisition front, Northern closed on 6 transactions during the third quarter totaling 2.2 net wells, 1,077 net mineral acres, and 182 net royalty acres (standardized to a 1/8 royalty interest).

WILLISTON BASIN ACQUISITION

On October 7, 2021, Northern announced that it entered into a definitive agreement to acquire non-operated interests across over 400 producing wellbores located primarily in Williams, McKenzie, Mountrail and Dunn Counties, ND for a purchase price of $154.0 million in cash, subject to typical closing adjustments. Northern has updated corporate guidance for the assets to be acquired in the guidance section below, which assumes a mid-to-late November closing date.

LIQUIDITY AND CAPITAL RESOURCES

Northern had total liquidity of $343.0 million as of September 30, 2021, consisting of cash of $2.0 million, and $341.0 million of committed borrowing availability under the revolving credit facility.

As of September 30, 2021, Northern’s total borrowings were $869.0 million, down $119.8 million since September 30, 2020. Total borrowings consist of $550.0 million in senior unsecured notes and $319.0 million outstanding on Northern’s revolving credit facility.

On November 3, 2021, Northern completed its regularly scheduled borrowing base redetermination, increasing both its elected commitment and borrowing base. Northern’s lending syndicate voted unanimously to increase the borrowing base to $850.0 million. Northern has chosen a $750.0 million elected commitment amount. Pro forma for this increase, as of September 30, 2021, we had $431.0 of committed borrowing availability under the revolving credit facility. The new borrowing base does not include any reserve value for Northern’s pending Williston Basin acquisition.

STOCKHOLDER RETURNS

On August 3, 2021, Northern’s Board of Directors declared a regular quarterly cash dividend for Northern’s common stock of $0.045 per share for stockholders of record as of September 30, 2021, which was paid on October 29, 2021. This represented a 50% increase from the prior quarter.

On October 7, 2021, Northern Management announced its plan to submit a request to Northern’s Board of Directors for a 33.3% increase to the quarterly common stock dividend to $0.06 per share upon closing of the Williston Basin acquisition that is expected to close in mid-November 2021.

On October 15, 2021, Northern’s Board of Directors declared all current and accrued cash dividends for Northern’s Series A Preferred Stock, to be paid on November 15, 2021, in the total amount of $7.2 million.

2021 FULL YEAR GUIDANCE
(all forecasts are provided on a 2-stream production basis)

 

Prior

 

Current

Annual Production (Boe per day)

49,500 - 54,250

 

51,750 - 53,750(1)

Oil as a Percentage of Sales Volumes

63% - 64%

 

63% - 64%

Net Wells Added to Production

38 - 40

 

38 - 40

Total Capital Expenditures (in millions) (2)

$215 - $260

 

$215 - $250

---------------------------

(1)

Includes approximately 500 - 560 Boe per day, annualized, from the pending Williston Basin acquisition, expected to close in mid to late November 2021.

(2)

Excludes non-budgeted acquisitions of Marcellus, Williston and Permian properties, but includes post-closing capital expenditures.

Operating Expenses and Differentials:

Prior

 

Current

Production Expenses (per Boe)

$8.60 - $8.90

 

$8.60 - $8.80

Production Taxes

9% - 10% of

Oil & Gas Sales

 

9% - 10% of

Oil & Gas Sales

Average Differential to NYMEX WTI (per Bbl)

$6.25 - $7.25

 

$5.75 - $6.25

Average Realization as a Percentage of NYMEX Henry Hub (per Mcf)

80% - 100%

 

90% - 100%

 

Prior

 

Current

General and Administrative Expense (per Boe):

 

 

 

Cash (excluding Marcellus, Williston and Permian transaction costs)

$0.80 - $0.85

 

$0.80 - $0.85

Non-Cash

$0.18

 

$0.18

THIRD QUARTER 2021 RESULTS

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

 

Three Months Ended September 30,

 

2021

 

2020

 

% Change

Net Production:

 

 

 

 

 

Oil (Bbl)

3,131,182

 

 

 

2,054,847

 

 

52

%

Natural Gas and NGLs (Mcf)

13,034,251

 

 

 

3,706,853

 

 

252

%

Total (Boe)

5,303,557

 

 

 

2,672,656

 

 

98

%

 

 

 

 

 

 

Average Daily Production:

 

 

 

 

 

Oil (Bbl)

34,035

 

 

 

22,335

 

 

52

%

Natural Gas and NGLs (Mcf)

141,677

 

 

 

40,292

 

 

252

%

Total (Boe)

57,647

 

 

 

29,051

 

 

98

%

 

 

 

 

 

 

Average Sales Prices:

 

 

 

 

 

Oil (per Bbl)

$

64.91

 

 

 

$

34.36

 

 

89

%

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

(12.52

)

 

 

21.11

 

 

 

Oil Net of Settled Oil Derivatives (per Bbl)

52.39

 

 

 

55.47

 

 

(6

)%

 

 

 

 

 

 

Natural Gas and NGLs (per Mcf)

4.33

 

 

 

0.83

 

 

 

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

(1.31

)

 

 

0.13

 

 

 

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

3.02

 

 

 

0.96

 

 

 

 

 

 

 

 

 

Realized Price on a Boe Basis Excluding Settled Commodity Derivatives

48.96

 

 

 

27.57

 

 

78

%

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

(10.62

)

 

 

16.40

 

 

 

Realized Price on a Boe Basis Including Settled Commodity Derivatives

38.34

 

 

 

43.97

 

 

(13

)%

 

 

 

 

 

 

Costs and Expenses (per Boe):

 

 

 

 

 

Production Expenses

$

8.15

 

 

 

$

9.04

 

 

(10

)%

Production Taxes

3.76

 

 

 

2.60

 

 

45

%

General and Administrative Expenses

1.04

 

 

 

1.72

 

 

(40

)%

Depletion, Depreciation, Amortization and Accretion

6.77

 

 

 

11.52

 

 

(41

)%

 

 

 

 

 

 

Net Producing Wells at Period End

601.8

 

 

 

468.8

 

 

28

%

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 swap contracts scheduled to settle after September 30, 2021.

Crude Oil Commodity Derivative Swaps(1)

Contract Period

 

Volume (Bbls)

 

Volume (Bbls/Day)

 

Weighted Average Price (per Bbl)

2021:

 

 

 

 

 

 

Q4

 

2,326,956

 

25,293

 

$55.27

2022:

 

 

 

 

 

 

Q1

 

2,137,480

 

23,750

 

$57.01

Q2

 

2,047,500

 

22,500

 

$57.55

Q3

 

2,058,500

 

22,375

 

$57.14

Q4

 

1,943,500

 

21,125

 

$56.96

2023:

 

 

 

 

 

 

Q1

 

596,250

 

6,625

 

$59.30

Q2

 

420,875

 

4,625

 

$61.72

Q3

 

115,000

 

1,250

 

$64.93

Q4

 

115,000

 

1,250

 

$64.93

_____________

(1)

This table does not include volumes subject to swaptions and call options, which could increase the amount of volumes hedged at the option of Northern’s counterparties. This table also does not include basis swaps. For additional information, see Note 11 to our financial statements included in our Form 10-Q filed with the SEC for the quarter ended September 30, 2021.

The following table summarizes Northern’s open natural gas commodity derivative swap contracts scheduled to settle after September 30, 2021.

Natural Gas Commodity Derivative Swaps

Contract Period

 

Gas (MMBTU)

 

Volume (MMBTU/Day)

 

Weighted Average Price (per Mcf)

2021:

 

 

 

 

 

 

Q4

 

8,784,210

 

95,481

 

$2.82

2022:

 

 

 

 

 

 

Q1

 

6,257,291

 

69,525

 

$3.07

Q2

 

5,460,000

 

60,000

 

$2.95

Q3

 

5,520,000

 

60,000

 

$2.95

Q4

 

4,300,000

 

46,739

 

$2.94

_____________

(1)

This table does not include volumes subject to collars. This table also does not include basis swaps. For additional information, see Note 11 to our financial statements included in our Form 10-Q filed with the SEC for the quarter ended September 30, 2021.

The following table presents Northern’s settlements on commodity derivative instruments and unsettled gains and losses on open commodity derivative instruments for the periods presented, which is included in the revenue section of Northern’s statement of operations:

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

(In thousands)

2021

 

2020

 

 

2021

 

2020

Cash Received (Paid) on Derivatives:

$

(56,318

)

 

 

$

43,837

 

 

 

$

(91,470

)

 

 

$

152,782

 

Non-Cash Gain (Loss) on Derivatives:

(71,845

)

 

 

(70,198

)

 

 

(373,540

)

 

 

124,800

 

Gain (Loss) on Derivative Instruments, Net

$

(128,163

)

 

 

$

(26,361

)

 

 

$

(465,010

)

 

 

$

277,582

 

CAPITAL EXPENDITURES & DRILLING ACTIVITY

(In millions, except for net well data)

 

Three Months Ended
September 30, 2021

Capital Expenditures Incurred:

 

 

Organic Drilling and Development Capital Expenditures

 

$

37.7

 

Ground Game Drilling and Development Capital Expenditures

 

$

15.3

 

Ground Game Acquisition Capital Expenditures

 

$

8.8

 

Other

 

$

1.4

 

Non-Budgeted Acquisitions

 

$

106.4

 

 

 

 

Net Wells Added to Production

 

6.5

 

 

 

 

Net Producing Wells (Period-End)

 

601.8

 

 

 

 

Net Wells in Process (Period-End)

 

43.1

 

Decrease in Wells in Process over Prior Period

 

(0.6

)

 

 

 

Weighted Average Gross AFE for Wells Elected to

 

$6.9 million

THIRD QUARTER 2021 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, November 5, 2021 at 10:00 a.m. Central Time.

Those wishing to listen to the conference call may do so via webcast or phone as follows:

Webcast: https://78449.themediaframe.com/dataconf/productusers/nog/mediaframe/46821/indexl.html
Dial-In Number: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13723773 - Northern Oil and Gas, Inc. Third Quarter 2021 Earnings Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13723773 - Replay will be available through November 12, 2021

UPCOMING CONFERENCE SCHEDULE

Bank of America Global Energy Conference

November 17-18, 2021

 

Piper Sandler Energy & Power Symposium

December 1-2, 2021

 

Capital One 16th Annual Energy Conference

December 6-8, 2021

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 premier basins within the United States. 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 production and 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 Northern’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 properties and properties pending acquisition; Northern’s ability to acquire additional development opportunities; potential or pending acquisition transactions; Northern’s ability to consummate pending acquisitions, and the anticipated timing of such consummation; the projected capital efficiency savings and other operating efficiencies and synergies resulting from Northern’s acquisition transactions; integration and benefits of property acquisitions, or the effects of such acquisitions on Northern’s cash position and levels of indebtedness; changes in Northern’s reserves estimates or the value thereof; disruptions to Northern’s business due to acquisitions and other significant transactions; infrastructure constraints and related factors affecting Northern’s properties; ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline; the COVID-19 pandemic and its related economic repercussions and effect on the oil and natural gas industry; 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; and 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
September 30,

 

Nine Months Ended
September 30,

(In thousands, except share and per share data)

2021

 

2020

 

2021

 

2020

Revenues

 

 

 

 

 

 

 

Oil and Gas Sales

$

259,669

 

 

 

$

73,680

 

 

 

$

642,717

 

 

 

$

224,541

 

 

Gain (Loss) on Commodity Derivatives, Net

(128,163

)

 

 

(26,361

)

 

 

(465,010

)

 

 

277,582

 

 

Other Revenue

1

 

 

 

3

 

 

 

2

 

 

 

12

 

 

Total Revenues

131,507

 

 

 

47,321

 

 

 

177,709

 

 

 

502,135

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

Production Expenses

43,236

 

 

 

24,159

 

 

 

120,246

 

 

 

88,132

 

 

Production Taxes

19,932

 

 

 

6,936

 

 

 

51,899

 

 

 

20,750

 

 

General and Administrative Expense

5,490

 

 

 

4,605

 

 

 

19,878

 

 

 

14,185

 

 

Depletion, Depreciation, Amortization and Accretion

35,885

 

 

 

30,786

 

 

 

98,013

 

 

 

129,350

 

 

Impairment Expense

 

 

 

199,489

 

 

 

 

 

 

962,205

 

 

Total Operating Expenses

104,543

 

 

 

265,975

 

 

 

290,036

 

 

 

1,214,622

 

 

 

 

 

 

 

 

 

 

Income (Loss) From Operations

26,964

 

 

 

(218,653

)

 

 

(112,327

)

 

 

(712,487

)

 

 

 

 

 

 

 

 

 

Other Income (Expense)

 

 

 

 

 

 

 

Interest Expense, Net of Capitalization

(14,586

)

 

 

(14,637

)

 

 

(43,120

)

 

 

(45,145

)

 

Write-off of Debt Issuance Costs

 

 

 

(1,543

)

 

 

 

 

 

(1,543

)

 

Gain (Loss) on Unsettled Interest Rate Derivatives, Net

92

 

 

 

224

 

 

 

454

 

 

 

(1,205

)

 

Gain (Loss) on Extinguishment of Debt, Net

 

 

 

1,592

 

 

 

(13,087

)

 

 

(3,718

)

 

Contingent Consideration Gain (Loss)

82

 

 

 

 

 

 

(292

)

 

 

 

 

Other Income (Expense)

2

 

 

 

13

 

 

 

5

 

 

 

14

 

 

Total Other Income (Expense)

(14,410

)

 

 

(14,351

)

 

 

(56,040

)

 

 

(51,597

)

 

 

 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

12,554

 

 

 

(233,004

)

 

 

(168,367

)

 

 

(764,084

)

 

 

 

 

 

 

 

 

 

Income Tax Provision (Benefit)

 

 

 

 

 

 

 

 

 

(166

)

 

 

 

 

 

 

 

 

 

Net Income (Loss)

$

12,554

 

 

 

$

(233,004

)

 

 

$

(168,367

)

 

 

$

(763,918

)

 

 

 

 

 

 

 

 

 

Cumulative Preferred Stock Dividend

(3,605

)

 

 

(3,718

)

 

 

(11,154

)

 

 

(10,986

)

 

 

 

 

 

 

 

 

 

Net Income (Loss) Attributable to Common Stockholders

$

8,949

 

 

 

$

(236,722

)

 

 

$

(179,521

)

 

 

$

(774,904

)

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Basic

$

0.14

 

 

 

$

(5.44

)

 

 

$

(2.97

)

 

 

$

(18.53

)

 

Net Income (Loss) Per Common Share – Diluted

$

0.13

 

 

 

$

(5.44

)

 

 

$

(2.97

)

 

 

$

(18.53

)

 

Weighted Average Common Shares Outstanding – Basic

65,856,479

 

 

 

43,517,074

 

 

 

60,404,584

 

 

 

41,812,553

 

 

Weighted Average Common Shares Outstanding – Diluted

66,629,566

 

 

 

43,517,074

 

 

 

60,404,584

 

 

 

41,812,553

 

 

CONDENSED BALANCE SHEETS

 

(In thousands, except par value and share data)

September 30, 2021

 

December 31, 2020

Assets

(Unaudited)

 

 

Current Assets:

 

 

 

Cash and Cash Equivalents

$

2,006

 

 

 

$

1,428

 

 

Accounts Receivable, Net

158,047

 

 

 

71,015

 

 

Advances to Operators

5,137

 

 

 

476

 

 

Prepaid Expenses and Other

2,393

 

 

 

1,420

 

 

Derivative Instruments

 

 

 

51,290

 

 

Total Current Assets

167,583

 

 

 

125,629

 

 

 

 

 

 

Property and Equipment:

 

 

 

Oil and Natural Gas Properties, Full Cost Method of Accounting

 

 

 

Proved

4,804,687

 

 

 

4,393,533

 

 

Unproved

24,656

 

 

 

10,031

 

 

Other Property and Equipment

2,779

 

 

 

2,451

 

 

Total Property and Equipment

4,832,122

 

 

 

4,406,015

 

 

Less – Accumulated Depreciation, Depletion and Impairment

(3,767,613

)

 

 

(3,670,811

)

 

Total Property and Equipment, Net

1,064,509

 

 

 

735,204

 

 

 

 

 

 

Derivative Instruments

 

 

 

111

 

 

Other Noncurrent Assets, Net

11,970

 

 

 

11,145

 

 

 

 

 

 

Total Assets

$

1,244,062

 

 

 

$

872,089

 

 

 

 

 

 

Liabilities and Stockholders' Equity (Deficit)

Current Liabilities:

 

 

 

Accounts Payable

$

65,912

 

 

 

$

35,803

 

 

Accrued Liabilities

100,443

 

 

 

68,673

 

 

Accrued Interest

4,248

 

 

 

8,341

 

 

Derivative Instruments

182,692

 

 

 

3,078

 

 

Contingent Consideration

242

 

 

 

493

 

 

Current Portion of Long-term Debt

 

 

 

65,000

 

 

Other Current Liabilities

1,635

 

 

 

1,087

 

 

Total Current Liabilities

355,172

 

 

 

182,475

 

 

 

 

 

 

Long-term Debt

858,415

 

 

 

879,843

 

 

Derivative Instruments

156,731

 

 

 

14,659

 

 

Asset Retirement Obligations

27,106

 

 

 

18,366

 

 

Other Noncurrent Liabilities

4,349

 

 

 

50

 

 

 

 

 

 

Total Liabilities

$

1,401,773

 

 

 

$

1,095,393

 

 

 

 

 

 

Commitments and Contingencies (Note 8)

 

 

 

 

 

 

Stockholders’ Equity (Deficit)

 

 

 

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

2,218,732 Series A Shares Outstanding at 6/30/2021

2,218,732 Series A Shares Outstanding at 12/31/2020

2

 

 

 

2

 

 

Common Stock, Par Value $.001; 135,000,000 Shares Authorized;

66,178,148 Shares Outstanding at 9/30/2021

45,908,779 Shares Outstanding at 12/31/2020

468

 

 

 

448

 

 

Additional Paid-In Capital

1,790,542

 

 

 

1,556,602

 

 

Retained Deficit

(1,948,723

)

 

 

(1,780,356

)

 

Total Stockholders’ Equity (Deficit)

(157,710

)

 

 

(223,304

)

 

Total Liabilities and Stockholders’ Equity (Deficit)

$

1,244,062

 

 

 

$

872,089

 

 

 

Non-GAAP Financial Measures

Adjusted Net Income, Adjusted EBITDA and Free Cash Flow 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) write-off of debt issuance costs, net of tax, (iii) (gain) loss on extinguishment of debt, net of tax, (iv) contingent consideration (gain) loss, net of tax, (v) acquisition transaction costs, net of tax, (vi) (gain) loss on unsettled interest rate derivatives, net of tax and (vii) impairment expense. 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) severance-cash, (vi) write-off of debt issuance costs, (vii) (gain) loss on extinguishment of debt, (viii) contingent consideration (gain) loss, (ix) acquisition transaction costs, (x) gain (loss) on unsettled interest rate derivatives (xi) (gain) loss on unsettled commodity derivatives, and (xii) impairment expense. Northern defines Free Cash Flow as cash flows from operations before changes in working capital and other items, less (i) capital expenditures, excluding non-budgeted acquisitions and (ii) preferred stock dividends. 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. Management believes Adjusted Net Income and Adjusted EBITDA 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. Management believes that Free Cash Flow is useful to investors as a measure of a company’s ability to internally fund its budgeted capital expenditures, to service or incur additional debt, and to measure success in creating stockholder value. 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. The non-GAAP financial measures included herein may be defined differently than similar measures used by other companies and should not be considered an alternative to, or more meaningful than, the comparable GAAP measures. From time to time Northern provides forward-looking Free Cash Flow estimates or targets; however, Northern is unable to provide a quantitative reconciliation of the forward looking non-GAAP measure to its most directly comparable forward looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward looking GAAP measure. The reconciling items in future periods could be significant.

Reconciliation of Adjusted Net Income

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

(In thousands, except share and per share data)

2021

 

2020

 

2021

 

2020

Net Income (Loss)

$

12,554

 

 

 

$

(233,004

)

 

 

$

(168,367

)

 

 

$

(763,918

)

 

Add:

 

 

 

 

 

 

 

Impact of Selected Items:

 

 

 

 

 

 

 

(Gain) Loss on Unsettled Commodity Derivatives

71,845

 

 

 

70,198

 

 

 

373,540

 

 

 

(124,800

)

 

Write-off of Debt Issuance Costs

 

 

 

1,543

 

 

 

 

 

 

1,543

 

 

(Gain) Loss on Extinguishment of Debt

 

 

 

(1,592

)

 

 

13,087

 

 

 

3,718

 

 

Contingent Consideration (Gain) Loss

(82

)

 

 

 

 

 

292

 

 

 

 

 

Acquisition Transaction Costs

677

 

 

 

 

 

 

6,204

 

 

 

 

 

(Gain) Loss on Unsettled Interest Rate Derivatives

(92

)

 

 

(224

)

 

 

(454

)

 

 

1,205

 

 

Impairment Expense

 

 

 

199,489

 

 

 

 

 

 

962,205

 

 

Selected Items, Before Income Taxes

72,347

 

 

 

269,415

 

 

 

392,670

 

 

 

843,871

 

 

Income Tax of Selected Items(1)

(20,801

)

 

 

(8,921

)

 

 

(54,954

)

 

 

(19,588

)

 

Selected Items, Net of Income Taxes

51,547

 

 

 

260,495

 

 

 

337,716

 

 

 

824,283

 

 

Adjusted Net Income

$

64,100

 

 

 

$

27,490

 

 

 

$

169,349

 

 

 

$

60,365

 

 

 

 

 

 

 

 

 

 

Weighted Average Shares Outstanding – Basic

65,856,479

 

 

 

43,517,074

 

 

 

60,404,584

 

 

 

41,812,553

 

 

Weighted Average Shares Outstanding – Diluted

76,348,278

 

 

 

53,582,333

 

 

 

70,888,853

 

 

 

51,707,412

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Basic

$

0.19

 

 

 

$

(5.35

)

 

 

$

(2.79

)

 

 

$

(18.27

)

 

Add:

 

 

 

 

 

 

 

Impact of Selected Items Before Income Tax

1.10

 

 

 

6.18

 

 

 

6.50

 

 

 

20.18

 

 

Impact of Income Tax on Selected Items

(0.32

)

 

 

(0.20

)

 

 

(0.91

)

 

 

(0.47

)

 

Adjusted Net Income Per Common Share – Basic

$

0.97

 

 

 

$

0.63

 

 

 

$

2.80

 

 

 

$

1.44

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Common Share – Diluted

$

0.16

 

 

 

$

(4.35

)

 

 

$

(2.38

)

 

 

$

(14.77

)

 

Add:

 

 

 

 

 

 

 

Impact of Selected Items Before Income Tax

0.95

 

 

 

5.03

 

 

 

5.55

 

 

 

16.32

 

 

Impact of Income Tax on Selected Items

(0.27

)

 

 

(0.17

)

 

 

(0.78

)

 

 

(0.38

)

 

Adjusted Net Income Per Common Share – Diluted

$

0.84

 

 

 

$

0.51

 

 

 

$

2.39

 

 

 

$

1.17

 

 

______________

(1)

For the three and nine months ended September 30, 2021, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $3.1 million and $41.2 million, respectively, for a change in valuation allowance. For the three and nine months ended September 30, 2020, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $57.1 million and $187.2 million, respectively, for a change in valuation allowance.

Reconciliation of Adjusted EBITDA

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

(In thousands)

2021

 

2020

 

2021

 

2020

Net Income (Loss)

$

12,554

 

 

 

$

(233,004

)

 

 

$

(168,367

)

 

 

$

(763,918

)

 

Add:

 

 

 

 

 

 

 

Interest Expense

14,586

 

 

 

14,637

 

 

 

43,120

 

 

 

45,145

 

 

Income Tax Provision (Benefit)

 

 

 

 

 

 

 

 

 

(166

)

 

Depreciation, Depletion, Amortization and Accretion

35,885

 

 

 

30,786

 

 

 

98,013

 

 

 

129,350

 

 

Impairment of Other Current Assets

 

 

 

 

 

 

 

 

 

 

 

Non-Cash Stock-Based Compensation

699

 

 

 

889

 

 

 

 

 

 

3,182

 

 

Severance-Cash

 

 

 

 

 

 

 

 

 

759

 

 

Write-off of Debt Issuance Costs

 

 

 

1,543

 

 

 

 

 

 

1,543

 

 

(Gain) Loss on Extinguishment of Debt

 

 

 

(1,592

)

 

 

13,087

 

 

 

3,718

 

 

Contingent Consideration (Gain) Loss

(82

)

 

 

 

 

 

292

 

 

 

 

 

Acquisition Transaction Costs

677

 

 

 

 

 

 

6,204

 

 

 

 

 

(Gain) Loss on Unsettled Interest Rate Derivatives

(92

)

 

 

(224

)

 

 

(454

)

 

 

1,205

 

 

(Gain) Loss on Unsettled Commodity Derivatives

71,845

 

 

 

70,198

 

 

 

373,540

 

 

 

(124,800

)

 

Impairment Expense

 

 

 

199,489

 

 

 

 

 

 

962,205

 

 

Adjusted EBITDA

$

136,071

 

 

 

$

82,723

 

 

 

$

367,685

 

 

 

$

258,224

 

 

Reconciliation of Free Cash Flow

 

 

Three Months Ended
September 30,

(In thousands)

2021

Net Cash Provided by Operating Activities

$

94,413

 

 

Exclude: Changes in Working Capital and Other Items

27,888

 

 

Less: Capital Expenditures (1)

(63,278

)

 

Less: Series A Preferred Dividends

(3,605

)

 

Free Cash Flow

$

55,418

 

 

_______________

(1)

Capital expenditures are calculated as follows:

 

Three Months Ended
September 30,

(In thousands)

2021

Cash Paid for Capital Expenditures

$

163,120

 

 

Less: Non-Budgeted Acquisitions

(106,197

)

 

Plus: Change in Accrued Capital Expenditures and Other

6,355

 

 

Capital Expenditures

$

63,278

 

 

 

Mike Kelly, CFA
Chief Strategy Officer
952-476-9800
mkelly@northernoil.com

Source: Northern Oil and Gas, Inc.