Document

“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 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.)

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.

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.

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

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.

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.

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.

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.

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.


	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	%


(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

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.


	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


(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

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.


	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.


	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


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


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