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First quarter 2019 production totaled 3.1 million Boe and averaged 34,598 Boe per day, a 92% increase from the prior year. Oil and gas sales in the first quarter increased 53% from the prior year to $132.7 million. Net income in the first quarter was a loss of $107.2 million or $0.29 per diluted share, primarily driven by a $152.2 million non-cash mark-to-market loss on hedges. Adjusted Net Income in the first quarter was $27.8 million or $0.07 per diluted share. Adjusted EBITDA totaled $104.8 million in the first quarter, an 87% increase from the prior year. Adjusted EBITDA was down sequentially primarily due to a decline in realized gas prices. (See “Non-GAAP Financial Measures” below.)

“Northern’s assets across the Williston Basin showed continued strong performance during the quarter, with recent wells added to production outperforming our expectations. As a result, we are raising our production forecast for the full year,” commented Brandon Elliott, Chief Executive Officer. “We believe a balance of production growth and cash flow generation is sustainable as we continue to lever our non-operator model to maximize returns.”

“Increased production and cash flows combined with our pending Flywheel acquisition should continue to improve our financial results as 2019 progresses. Our near-term goals remain simple: continued growth of free cash flow, reduction of our debt obligations, and growth of debt-adjusted cash flow per share. We will pursue these goals while staying focused on Northern’s core objective of generating abundant, sustainable free cash flow to deliver returns to our shareholders regardless of commodity prices.”

First quarter production was modestly better than expected as Northern added 7.0 net wells to production during the quarter, with 3.3 of those net wells added in March. Oil price differentials of $6.19 per barrel are trending as expected, beginning the year at the higher end of guidance and projected to improve throughout the year. The timing of net well additions combined with ongoing production curtailments resulted in an increase in lease operating expenses (“LOE”) to $7.92 per Boe in the first quarter. Curtailments are scheduled to roll off over the next several quarters and Northern still expects annual LOE of between $6.75 - $7.75 per Boe for the year, unchanged from previous guidance. Total general and administrative expenses were $1.94 per Boe in the first quarter. Cash general and administrative expenses were $1.06 per Boe in the first quarter, at the lower end of guidance.

Despite relatively flat industry activity, operator budget constraints, and commodity price volatility during the first quarter, Northern saw a pick-up in activity on its Williston Basin acreage and an increase in smaller “ground game” acquisition opportunities. Wells in process increased by 1.9 net wells during the quarter to a total of 24.7 net wells, the most net wells and some of the highest expected EURs on the wells in process list in the company’s history. The additional capital associated with that increase, combined with the $8.4 million allocated to ground game acquisitions, resulted in total capital expenditures of $82.9 million for the first quarter. Northern spent $15.1 million on share repurchases in the first quarter. Stronger production combined with more normalized costs will help drive improvements to cash flow for the remainder of 2019.

“Northern experienced modest unit cost pressures associated with curtailments and deferments through much of the first quarter, yet our assets still delivered excess cash flow to deploy to our ground game program and return capital to our shareholders,” said Nick O’Grady, Chief Financial Officer. “The remainder of 2019 looks promising as production continues to ramp up and increased costs in the first part of the year appear to be transitory. Our production outlook continues to improve

Current Williston Basin activity levels continue to support the company’s 2019 plan to add between 28 and 32 net wells to production during the year. As production curtailments and weather-related delays begin to abate, Northern expects second quarter production to average between 34,500 and 35,500 Boe per day and to grow sequentially in the second half of 2019. As a result of improved well performance to date, Northern now expects production (excluding the recently announced Flywheel acquisition) to average between 35,000 and 36,000 Boe per day for the full year of 2019, a 500 Boe per day increase compared to prior guidance. Northern intends to update second half 2019 production guidance, to incorporate the Flywheel acquisition, in connection with the release of its second quarter results. Northern’s previous cost and capital spending plan remains unchanged.


	Three Months Ended March 31,
	2019		2018		% Change
Net Production:
Oil (Bbl)	2,541,232		1,354,602		88	%
Natural Gas and NGLs (Mcf)	3,435,784		1,589,514		116	%
Total (Boe)	3,113,863		1,619,521		92	%

Average Daily Production:
Oil (Bbl)	28,236		15,051		88	%
Natural Gas and NGLs (Mcf)	38,175		17,661		116	%
Total (Boe)	34,598		17,995		92	%

Average Sales Prices:
Oil (per Bbl)	$	48.64	$	58.43	(17)	%
Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)	4.94		(6.00)		(182)	%
Oil Net of Settled Derivatives (per Bbl)	53.58		52.43		2	%
Natural Gas and NGLs (per Mcf)	2.64		4.87		(46)	%
Realized Price on a Boe Basis Including all Realized Derivative Settlements	46.64		48.63		(4)	%

Costs and Expenses (per Boe):
Production Expenses	$	7.92	$	7.71	3	%
Production Taxes	4.02		4.89		(18)	%
General and Administrative Expense	1.94		1.03		88	%
Depletion, Depreciation, Amortization and Accretion	14.49		11.50		26	%

Net Producing Wells at Period End	332.5		234.7		42	%


Crude Oil Derivative Swaps
Contract Period	Volume (Bbls)	Weighted Average Price (per Bbl)
2019:

2Q	1,925,750	$63.01
3Q	1,942,480	$63.07
4Q	1,853,800	$63.43
2020:
1Q	1,779,050	$60.20
2Q	1,801,800	$59.25
3Q	1,752,600	$59.17
4Q	1,622,880	$58.81
2021:
1Q	1,064,700	$58.67
2Q	969,150	$59.63
3Q	345,000	$55.28
4Q	345,000	$55.28
2022:
1Q	225,000	$55.03
2Q	91,000	$55.08
3Q	92,000	$55.08
4Q	92,000	$55.08

As of March 31, 2019, Northern had $3.9 million in cash and $147.0 million outstanding on its revolving credit facility. Northern had total liquidity of $281.9 million as of March 31, 2019, consisting of cash and borrowing availability under the revolving credit facility. Total debt as of March 31, 2019 was up approximately $8.7 million compared to 2018 year-end, primarily due to share repurchases and an increase in ground game acquisitions during the first quarter.


						Three Months Ended March 31, 2019
Capital Expenditures Incurred:
Drilling and Development Capital Expenditures						$74.0 million
Acquisition of Oil and Natural Gas Properties						$8.4 million
Other						$0.5 million

Net Organic Wells Added to Production						7.0

Net Producing Wells (Period-End)						332.5

Net Wells in Process (Period-End)						24.7
Increase in Wells in Process over Prior Period						1.9
Weighted Average AFE for Wells Elected to Year-to-Date						$8.2 million

Capitalized costs are a function of the number of net well additions during the period, and changes in wells in process from beginning to end of period. Capital expenditures attributable to the 1.9 well increase in net wells in process for the three months ended March 31, 2019 are reflected in the amounts included for “Drilling and Development Capital Expenditures” in the table above.

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, 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.


	Three Months Ended March 31,
(In thousands, except share and per share data)	2019		2018
REVENUES
Oil and Gas Sales	$	132,684	$	86,881
Gain (Loss) on Derivative Instruments, Net	(139,623)		(20,271)
Other Revenue	5		3
Total Revenues	(6,934)		66,613

OPERATING EXPENSES
Production Expenses	24,666		12,488
Production Taxes	12,520		7,922
General and Administrative Expenses	6,051		1,667
Depletion, Depreciation, Amortization and Accretion	45,134		18,631

Total Operating Expenses	88,371		40,708

INCOME (LOSS) FROM OPERATIONS	(95,305)		25,905

OTHER INCOME (EXPENSE)
Interest Expense, Net of Capitalization	(19,548)		(23,107)


Debt Exchange Derivative Gain	6,287		—
Contingent Consideration Gain	1,392		—

Other Income	12		167
Total Other Income (Expense)	(11,857)		(22,940)

INCOME (LOSS) BEFORE INCOME TAXES	(107,162)		2,965

INCOME TAX PROVISION (BENEFIT)	—		—

NET INCOME (LOSS)	$	(107,162)	$	2,965

Net Income (Loss) Per Common Share – Basic	$	(0.29)	$	0.05
Net Income (Loss) Per Common Share – Diluted	$	(0.29)	$	0.05
Weighted Average Shares Outstanding – Basic	371,448,566		65,215,148
Weighted Average Shares Outstanding – Diluted	371,448,566		65,382,772


(In thousands, except par value and share data)	March 31, 2019		December 31, 2018
ASSETS	(Unaudited)
Current Assets:
Cash and Cash Equivalents	$	3,944	$	2,358
Accounts Receivable, Net	90,509		96,353
Advances to Operators	43		268
Prepaid Expenses and Other	12,182		12,360
Derivative Instruments	18,578		115,870
Income Tax Receivable	1,205		1,205
Total Current Assets	126,461		228,415

Property and Equipment:
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved	3,511,605		3,431,428
Unproved	6,997		4,307
Other Property and Equipment	1,003		998
Total Property and Equipment	3,519,605		3,436,732
Less – Accumulated Depreciation, Depletion and Impairment	(2,278,914)		(2,233,987)
Total Property and Equipment, Net	1,240,691		1,202,745

Derivative Instruments	17,839		61,843

Deferred Income Taxes	420		420

Other Noncurrent Assets, Net	10,368		10,223

Total Assets	$	1,395,779	$	1,503,645

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts Payable	$	154,339	$	135,483
Accrued Expenses	1,823		2,769
Accrued Interest	16,901		16,468
Debt Exchange Derivative	9,225		18,183
Derivative Instruments	5,882		—
Contingent Consideration	37,160		58,069


Other Current Liabilities	724		555

Total Current Liabilities	226,054		231,526

Long-term Debt, Net	839,229		830,203

Derivative Instruments	4,991		—


Asset Retirement Obligations	12,364		11,946
Other Noncurrent Liabilities	381		105

TOTAL LIABILITIES	$	1,083,019	$	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; 376,800,478 Shares Outstanding at 3/31/2019 378,333,070 Shares Outstanding at 12/31/2018	377		378
Additional Paid-In Capital	1,216,429		1,226,371
Retained Deficit	(904,046)		(796,884)
Total Stockholders’ Equity	312,760		429,865
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,395,779	$	1,503,645

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) debt exchange derivative gain (loss), net of tax, and (iii) contingent consideration gain (loss), 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) (gain) loss on the mark-to-market of derivative instruments, (v) non-cash share-based compensation expense, (vi) debt exchange derivative gain (loss), and (vii) contingent consideration gain (loss). 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.


	Three Months Ended March 31,
(In thousands, except share and per share data)	2019		2018
Net Income (Loss)	$	(107,162)	$	2,965
Add:
Impact of Selected Items:
Loss on the Mark-to-Market of Derivative Instruments	152,169		12,141




Debt Exchange Derivative Gain	(6,287)		—
Contingent Consideration Gain	(1,392)		—

Selected Items, Before Income Taxes	144,490		12,141
Income Tax of Selected Items(1)	(9,506)		(3,853)
Selected Items, Net of Income Taxes	134,984		8,288

Adjusted Net Income	$	27,822	$	11,253

Weighted Average Shares Outstanding – Basic	371,448,566		65,215,148
Weighted Average Shares Outstanding – Diluted	372,715,932		65,382,772

Net Income (Loss) Per Common Share – Basic	$	(0.29)	$	0.05
Add:
Impact of Selected Items, Net of Income Taxes	0.36		0.12
Adjusted Net Income Per Common Share – Basic	$	0.07	$	0.17

Net Income (Loss) Per Common Share – Diluted	$	(0.29)	$	0.05
Add:
Impact of Selected Items, Net of Income Taxes	0.36		0.12
Adjusted Net Income Per Common Share – Diluted	$	0.07	$	0.17

(1)For the three months ended March 31, 2019, this represents a tax impact using an estimated tax rate of 24.5% which includes a $25.9 million adjustment for an increase in valuation allowance. For the three months ended March 31, 2018, this represents a tax impact using an estimated tax rate of 25.5%, which includes a $0.8 million adjustment for a reduction in valuation allowance.


	Three Months Ended March 31,
(In thousands)	2019		2018
Net Income (Loss)	$	(107,162)	$	2,965
Add:
Interest Expense	19,548		23,107
Income Tax Provision (Benefit)	—		—
Depreciation, Depletion, Amortization and Accretion	45,134		18,631

Non-Cash Stock-Based Compensation	2,751		(886)


Debt Exchange Derivative Gain	(6,287)		—
Contingent Consideration Gain	(1,392)		—

Loss on the Mark-to-Market of Derivative Instruments	152,169		12,141
Adjusted EBITDA	$	104,761	$	55,958


Operating Expenses:			2019
Production Expenses (per Boe)			$6.75 - $7.75
Production Taxes (% of Oil & Gas Sales)			~ 9.1%
General and Administrative Expense (per Boe):
Cash			$1.00 - $1.25
Non-Cash			~ $0.50

Average Differential to NYMEX WTI			$4.50 - $6.50