MINNETONKA, Minn., May 8, 2017 /PRNewswire/ -- Northern Oil and Gas, Inc. (NYSE MKT: NOG) today announced 2017 first quarter results and completion of the semi-annual borrowing base redetermination under Northern's revolving credit facility.

HIGHLIGHTS

• Production totaled 1,196,924 barrels of oil equivalent ("Boe") for the first quarter, averaging 13,299 Boe per day.
• Northern's first quarter 2017 producing well additions have a 30 day initial production average of 1,485 Boe per day, a 34% increase over the 2016 additions.
• Northern's 2016 producing well additions are tracking a 1 million Boe average type curve, a 59% increase over the 2015 additions.
• Northern has participated in 27 gross wells since the beginning of 2016 with completions that used at least 10 million pounds of proppant; these wells are tracking a 1.2 million Boe average type curve.
• Northern completed the semi-annual redetermination under its revolving credit facility with the borrowing base established at $325 million. Based on this new borrowing base, Northern had available liquidity of $196.5 million as of March 31, 2017.

Northern's GAAP net income for the first quarter of 2017 was $16.9 million. Adjusted net income for the quarter was a loss of $0.1 million. Adjusted EBITDA for the quarter was $29.6 million. See "Non-GAAP Financial Measures" below for additional information on these measures.

MANAGEMENT COMMENT

"Northern's ability to allocate our capital expenditures to the highest return wells is allowing us to maintain production levels despite our dramatic reduction in capital expenditures since 2015," commented Northern's Interim CEO and CFO, Tom Stoelk. "Increased well productivity is being aided by the enhanced completion designs, which is improving returns as we execute on our capital allocation focused business plan. As the weather improves, an increase in completions is expected to drive production growth during the second half of 2017."

GUIDANCE

Northern continues to expect 2017 total annual production to equal or modestly exceed 2016 total production. Northern expects that it will add approximately 12 net wells to production during the year, based on a preliminary capital budget of $102.2 million (including acreage and development capital). Net well additions will be weighted to the second half of 2017, which should result in sequential production growth in the third and fourth quarters. Management's current expectations for 2017 operating metrics are as follows:

LIQUIDITY

At March 31, 2017, Northern had $134.0 million in outstanding borrowings under its revolving credit facility, a $10 million reduction from December 31, 2016. In May 2017, Northern completed the semi-annual redetermination under its revolving credit facility with the borrowing base established at $325 million. Based on this new borrowing base, Northern had available liquidity of $196.5 million as of March 31, 2017, composed of $5.5 million in cash and $191.0 million of revolving credit facility availability.

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 derivative contracts scheduled to settle after March 31, 2017.

CAPITAL EXPENDITURES & DRILLING ACTIVITY

For the first quarter of 2017, the weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in (consented) was $6.6 million.

ACREAGE

As of March 31, 2017, Northern leased approximately 151,672 net acres targeting the Williston Basin Bakken and Three Forks formations. As of March 31, 2017, approximately 84% of Northern's North Dakota acreage position, and approximately 82% of Northern's total acreage position was developed, held by production or held by operations.

FIRST QUARTER 2017 RESULTS

The following table sets forth selected operating and financial data for the periods indicated.

Oil and Natural Gas Sales

In the first three months of 2017, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 72% as compared to the first three months of 2016, driven by a 77% increase in realized prices, excluding the effect of settled derivatives, which was partially offset by a 3% decrease in production. The higher average realized price in the first three months of 2017 as compared to the same period in 2016 was principally driven by higher average NYMEX oil and natural gas prices and a lower oil price differential. Oil price differential during the first three months of 2017 was $8.06 per barrel, as compared to $9.02 per barrel in the first three months of 2016.

Derivative Instruments (Hedges)

Northern enters into derivative instruments to manage the price risk attributable to future oil production. Gain (loss) on derivative instruments, net was a gain of $17.0 million in the first three months of 2017, compared to a gain of $3.5 million in the first three months of 2016. Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses recognized on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses incurred on derivative instruments outstanding at period end.

The average NYMEX oil price for the first three months of 2017 was $51.78 compared to $33.63 for the first three months of 2016. Northern's average realized price (including all cash derivative settlements) in the first three months of 2017 was $40.73 per Boe compared to $43.64 per Boe in the first three months of 2016. The gain (loss) on settled derivatives decreased the average realized price per Boe by $0.08 in the first three months of 2017 and increased the average realized price per Boe by $20.63 in the first three months of 2016.

Production Expenses

Production expenses were $11.7 million in the first three months of 2017 compared to $12.0 million in the first three months of 2016. On a per unit basis, production expenses increased to $9.75 per Boe in the first three months of 2017, compared to $9.70 per Boe in the first three months of 2016. This increase was due to a 3% decline in production levels over which fixed costs are spread, partially offset by a reduction in the aggregate dollar amount of production expenses. On an absolute dollar basis, production expenses in the first three months of 2017 were 2% lower when compared to the first three months of 2016 due primarily to lower contract labor and maintenance costs, which was partially offset by a 4% increase in the total number of net producing wells.

Production Taxes

Production taxes were $4.5 million in the first three months of 2017 compared to $2.8 million in the first three months of 2016. The increase is due to higher commodity prices, which substantially increased oil and natural gas sales in the first three months of 2017 as compared to the first three months of 2016. As a percentage of oil and natural gas sales, production taxes were 9.1% and 9.8% in the first three months of 2017 and 2016, respectively. This decrease in production tax rates is due to a change in sales mix. Production taxes on natural gas and NGL sales are at a lower percentage than that of crude oil sales. Crude oil sales represented 91% of oil and gas sales in the first three months of 2017 compared to 96% in the first three months of 2016.

General and Administrative Expense

General and administrative expense was $3.6 million in the first three months of 2017 compared to $4.3 million in the first three months of 2016. The decrease was due to a $1.0 million reduction in compensation expenses, primarily driven by a decrease in incentive compensation and lower non-cash share-based compensation expense, partially offset by a $0.3 million increase in legal and other professional fees.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion ("DD&A") was $12.8 million in the first three months of 2017 compared to $17.8 million in the first three months of 2016. Depletion expense, the largest component of DD&A, decreased by $5.0 million in the first three months of 2017 compared to the first three months of 2016. The aggregate decrease in depletion expense was driven by a 26% decrease in the depletion rate per Boe, as well as a 3% decrease in production levels. On a per unit basis, depletion expense was $10.58 per Boe in the first three months of 2017 compared to $14.35 per Boe in the first three months of 2016. The 2017 depletion rate per Boe was lower due to the impairment of oil and natural gas properties in 2016, which lowered the depletable base. Depreciation, amortization and accretion was $0.2 million and $0.1 million in the first three months of 2017 and 2016, respectively.

Impairment of Oil and Natural Gas Properties

No impairment of oil and natural gas properties was recorded in the first three months of 2017. As a result of low prevailing commodity prices and their effect on the proved reserve values of our properties, Northern recorded a non-cash ceiling test impairment of $104.3 million for the first three months of 2016. The impairment charge affected Northern's reported net income in 2016 but did not reduce cash flow.

Interest Expense

Interest expense, net of capitalized interest, was $16.3 million for the first three months of 2017 compared to $16.1 million in the first three months of 2016.

Income Tax Provision

During the first three months of 2017 and 2016, no income tax expense (benefit) was recorded on the income (loss) before income taxes due to the valuation allowance placed on our net deferred tax asset.

Non-GAAP Financial Measures

Adjusted Net Income (Loss) for the first quarter of 2017 was a loss of $0.1 million (representing approximately $0.00 per diluted share), compared to income of $0.5 million (representing approximately $0.01 per diluted share) for the first quarter of 2016. The decrease in Adjusted Net Income (Loss) is primarily due to lower realized commodity prices (after the effect of settled derivatives) and lower production levels. Northern defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) impairment of oil and natural gas properties, net of tax, and (iii) write-off of debt issuance costs, net of tax.

Adjusted EBITDA for the first quarter of 2017 was $29.6 million, compared to Adjusted EBITDA of $36.2 million for the first quarter of 2016. The decrease in Adjusted EBITDA is primarily due to lower realized commodity prices (after the effect of settled derivatives) and lower production levels. 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) write-off of debt issuance costs and (vii) impairment of oil and natural gas properties.

Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. A reconciliation of these measures to the most directly comparable GAAP measure is included in the accompanying financial tables found later in this release. 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 results included herein provide useful information to both management and investors by excluding certain expenses and unrealized derivatives 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.

FIRST QUARTER 2017 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 Monday, May 8, 2017 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:

Dial-In Number: (855) 638-5677 (US/Canada) and (262) 912-4762 (International) Conference ID: 14741485 - Northern Oil and Gas, Inc. First Quarter 2017 Conference CallReplay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)Replay Access Code: 14741485 - Replay will be available through May 15, 2017

UPCOMING CONFERENCE SCHEDULE

Louisiana Energy Conference - Al Petrie Advisors May 30 - June 2, 2017, New Orleans, LA

2017 RBC Capital Markets' Global Energy and Power Executive Conference June 6 - 7, 2017, New York, NY

EnerCom's The Oil & Gas Conference 22 August 13 - 17, 2017, Denver, CO

ABOUT NORTHERN OIL AND GAS

Northern Oil and Gas, Inc. is an exploration and production company with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana.

More information about Northern Oil and Gas, Inc. can be found at www.NorthernOil.com.

SAFE HARBOR

This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the "Securities Act") and the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical facts included in this release regarding Northern's financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as "estimate," "project," "predict," "believe," "expect," "continue," "anticipate," "target," "could," "plan," "intend," "seek," "goal," "will," "should," "may" or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond 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, 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 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, services 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.

CONTACT:

Brandon Elliott, CFA Executive Vice President,Corporate Development and Strategy952-476-9800[email protected]

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SOURCE Northern Oil and Gas, Inc.