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Northern Oil and Gas, Inc. Announces First Quarter 2019 Results and Increases 2019 Production Guidance

MINNEAPOLIS--(BUSINESS WIRE)--

  • Production increased 92% over the prior year, averaging 34,598 barrels of oil equivalent (“Boe”) per day; strong well performance driving an increase in 2019 production guidance with no change to capital spending guidance.
  • Drilling and development capital expenditures totaled $74.0 million, a 5% reduction versus the prior quarter.
  • Cash flow from operations, excluding an $11.4 million net increase from changes in working capital, was $87.5 million.
  • Northern spent $15.1 million on share repurchases in the quarter and $8.4 million on ground game acquisitions.

Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s first quarter results and provided updated 2019 guidance.

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.”

Production and Operating Costs

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.

2019 Cash Flow Allocation

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 due to increased well efficiencies across the basin, while we anticipate costs and capital spending to remain within our prior guidance ranges.”

2019 Production Guidance Up, Capital Unchanged

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.

Additional information regarding Northern’s current expectations are included in the table below.

   
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
 

FIRST QUARTER 2019 RESULTS

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

 
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 %
 

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 tables summarize Northern’s open crude oil derivative and basis swap contracts scheduled to settle after March 31, 2019.

 
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
 

Crude Oil Derivative Basis Swaps(1)

Contract Period

Total Volumes (Bbls)

Weighted Average Differential
($/Bbl)

04/01/2019 - 12/31/2019

2,841,000

($2.42)

 

________________

(1) Basis swaps are settled using the TMX UHC 1a index, as published by NGX.

 

LIQUIDITY

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.

CAPITAL EXPENDITURES & DRILLING ACTIVITY

 

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.

ACREAGE

As of March 31, 2019, Northern controlled leasehold of approximately 160,394 net acres targeting the Bakken and Three Forks formations of the Williston Basin, and approximately 91% of this total acreage position was developed, held by production, or held by operations.

FIRST QUARTER 2019 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, May 10, 2019 at 9:00 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: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13690610 - Northern Oil and Gas, Inc. First Quarter 2019 Conference Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13690610 - Replay will be available through May 17, 2019

UPCOMING CONFERENCE SCHEDULE

UBS Global Oil & Gas Conference
     May 21, 2019, Austin, TX

Louisiana Energy Conference
     May 28-31, 2019, New Orleans, LA

Bank of America Merrill Lynch Energy Credit Conference
     June 5, 2019, New York City, NY

Stifel Cross-Sector Insight Conference
     June 10-12, 2019, Boston, MA

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 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.

 

CONDENSED STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2019 AND 2018
(UNAUDITED)

 
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  
 
 

CONDENSED BALANCE SHEETS
MARCH 31, 2019 AND DECEMBER 31, 2018

   
(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  
 

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 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.

 

Reconciliation of Adjusted Net Income

 
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.

 

Reconciliation of Adjusted EBITDA

 
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 Share-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  
 

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