ex991_11062014.htm

2014 THIRD QUARTER HIGHLIGHTS

·	Third quarter 2014 production increased 8% sequentially and 26% year over year to 1,513,205 barrels of oil equivalent (“Boe”), or 16,448 average Boe per day

·	Oil and gas sales totaled $119.2 million during the third quarter

·	Northern added 167 gross (13.8 net) wells to production during the third quarter

·	The company raised full year 2014 production guidance to an expected 25% year over year increase

·	Northern has approximately 4.0 million barrels of oil hedged for 2015 at an average price of $89.43 per barrel

Northern’s GAAP net income for the third quarter of 2014 was $58.0 million, or $0.95 per diluted share. Adjusted Net Income for the third quarter of 2014 was $15.6 million, or $0.26 per diluted share. Adjusted EBITDA for the third quarter of 2014 was $81.4 million, an increase of 9% when compared to the third quarter of 2013. See “Non-GAAP Financial Measures” below for additional information on these measures.

“Northern had another strong quarter of drilling and completion activity, resulting in continued sequential production growth and a record 359 gross (25.0 net) wells in process at the end of the quarter,” commented Northern Oil Chairman and Chief Executive Officer Michael Reger. “Our well productivity continued to improve as our new well additions were again heavily concentrated in the core counties of Mountrail, McKenzie, Williams and Dunn. In addition, given market volatility our non-operated business model allowed us to quickly tighten our internal capital allocation process to incorporate the recent changes in oil prices. We intend to monitor and adjust our capital allocation decisions as conditions merit. Our capital discipline and liquidity position, coupled with our extensive hedge book, puts us in a strong position as we plan for 2015.”

Field conditions in the third quarter were as expected, allowing Northern to add 167 gross (13.8 net) wells to production, which brought Northern’s total producing well count to 2,197 gross (177.5 net) as of September 30, 2014. The strong pace of drilling activity continued, and as a result, Northern’s number of wells drilling or awaiting completion hit a new record of 359 gross (25.0 net) as of September 30, 2014.

During the third quarter of 2014, Northern incurred $110.1 million of capital expenditures on drilling and completion and capitalized workover costs. This amount includes percentage of completion accrual amounts that are attributable to the current wells in process. In addition, during the third quarter Northern spent $11.6 million on acreage and other acquisition activities in the Williston Basin, and incurred $2.3 million of other capitalized costs.

HEDGING UPDATE

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 oil derivative contracts as of September 30, 2014, by fiscal quarter:

		SWAPS				COSTLESS COLLARS
Contract Period		Volume (Bbls)		Weighted Average Price (per Bbl)		Volume (Bbls)		Weighted Average Floor/Ceiling Price (per Bbl)
2014:
	Q4		975,000	$	89.77		60,000	$	90.00 - $99.05
2015:
	Q1		990,000	$	89.03		–		–
	Q2		990,000	$	89.03		–		–
	Q3		990,000	$	89.82		–		–
	Q4		990,000	$	89.82		–		–
2016:
	Q1		450,000	$	90.00		–		–
	Q2		450,000	$	90.00		–		–

	Three Months Ended September 30,
	2014			2013			% Change
Net Production:
Oil (Bbl)		1,348,146			1,093,464			23
Natural Gas and NGLs (Mcf)		990,351			642,338			54
Total (Boe)		1,513,205			1,200,520			26

Average Daily Production:
Oil (Bbl)		14,654			11,885			23
Natural Gas and NGLs (Mcf)		10,765			6,982			54
Total (Boe)		16,448			13,049			26

Average Sales Prices:
Oil (per Bbl)	$	84.32		$	95.08			(11	)
Effect of Loss on Settled Derivatives on Average Price (per Bbl)		(5.20	)		(7.40	)		(30	)
Oil Net of Settled Derivatives (per Bbl)		79.12			87.68			(10	)
Natural Gas and NGLs (per Mcf)		5.56			5.08			9
Realized Price on a Boe Basis Including all Realized Derivative Settlements		74.13			82.58			(10	)

Operating Expenses (per Boe):
Production Expenses	$	9.73		$	9.56			2
Production Taxes		7.98			8.27			(4	)
General and Administrative Expense		3.11			3.47			(10	)
Depletion, Depreciation, Amortization and Accretion		30.17			26.74			13

In the third quarter of 2014, oil, natural gas and NGL sales, excluding the effect of settled derivatives, were $119.2 million, an increase of 11% as compared to the third quarter of 2013, driven by a 26% increase in production that was partially offset by a 12% decrease in realized prices, excluding the effect of settled derivatives. The lower average realized price in the third quarter of 2014 as compared to the same period in 2013 was driven by lower average NYMEX oil prices and a higher oil price differential. Northern’s oil price differential during the third quarter of 2014 was $12.92 per barrel, as compared to $9.04 per barrel in the third quarter of 2013.

Northern pays production tax as a percentage of total oil and gas sales, before the effect of settled derivatives. These costs were $12.1 million in the third quarter of 2014 compared to $9.9 million in the third quarter of 2013. As a percentage of oil and gas sales, our production taxes were 10.1% and 9.3% in the third quarter of 2014 and 2013, respectively. This increase in production tax rates as a percentage of oil and gas sales in the third quarter of 2014 is due to a declining proportion of Northern’s production that qualifies for lower initial tax rates.

General and Administrative Expense

Depletion, depreciation, amortization and accretion (“DD&A”) was $45.6 million in the third quarter of 2014 compared to $32.1 million in the third quarter of 2013. Depletion expense, the largest component of DD&A, was $30.02 per Boe in the third quarter of 2014 compared to $26.66 per Boe in the third quarter of 2013. The aggregate increase in depletion expense in the third quarter of 2014 compared to the third quarter of 2013 was driven by a 26% increase in production and a 13% increase in the depletion rate per Boe.

Interest Expense

Interest expense, net of capitalized interest, was $10.6 million in the third quarter of 2014 compared to $9.2 million in the third quarter of 2013. The increase in interest expense was primarily due to increased borrowings on our revolving credit facility.

Income Tax Provision

The provision for income taxes was $35.1 million in the third quarter of 2014 compared to $1.0 million in the third quarter of 2013. The effective tax rate in the third quarter of 2014 was 37.7% compared to an effective tax rate of 37.6% in the third quarter of 2013.

Net Income

Net income was a gain of $58.0 million, or approximately $0.95 per diluted share, for the third quarter of 2014, compared to net income of $1.7 million, or approximately $0.03 per diluted share, for the third quarter of 2013. Net income in the third quarter of 2014 was impacted by a non-cash gain on the mark-to-market of derivative instruments, net of tax, totaling $42.7 million, compared to a $18.3 million loss, net of tax, in the third quarter of 2013.

Non-GAAP Financial Measures

Adjusted Net Income for the third quarter of 2014 was $15.6 million (representing approximately $0.26 per diluted share), compared to $20.0 million (representing approximately $0.32 per diluted share) for the third quarter of 2013. The decrease in non-GAAP Adjusted Net Income is primarily due to lower realized commodity prices as well as higher interest, operating and depletion expenses, which were partially offset by the continued addition of crude oil and natural gas production. Northern defines Adjusted Net Income as net income excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax and (ii) certain legal settlements, net of tax.

Adjusted EBITDA for the third quarter of 2014 was $81.4 million, compared to Adjusted EBITDA of $74.6 million for the third quarter of 2013. The increase in Adjusted EBITDA is primarily due to our continued addition of crude oil and natural gas production from new wells, which was partially offset by lower realized commodity prices in 2014 compared to 2013. Northern defines Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) (gain) loss on the mark-to-market of derivative instruments and (v) non-cash share based compensation expense.

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.

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,” “anticipate,” “target,” “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, 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 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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
REVENUES
Oil and Gas Sales	$	119,191,594		$	107,232,064		$	337,149,610		$	270,026,894
Loss on Settled Derivatives		(7,017,599	)		(8,096,075	)		(25,084,349	)		(8,966,175	)
Gain (Loss) on the Mark-to-Market of Derivative Instruments		68,600,900			(29,353,161	)		25,433,684			(27,254,147	)
Other Revenue		2,594			1,372			5,863			37,514
Total Revenues		180,777,489			69,784,200			337,504,808			233,844,086

OPERATING EXPENSES
Production Expenses		14,717,257			11,471,867			39,428,008			30,510,248
Production Taxes		12,068,494			9,931,345			34,073,083			25,303,805
General and Administrative Expense		4,698,972			4,164,335			12,677,481			12,068,439
Depletion, Depreciation, Amortization and Accretion		45,646,232			32,103,607			123,959,402			85,455,425
Total Expenses		77,130,955			57,671,154			210,137,974			153,337,917

INCOME FROM OPERATIONS		103,646,534			12,113,046			127,366,834			80,506,169

OTHER INCOME (EXPENSE)
Interest Expense, Net of Capitalization		(10,624,246	)		(9,212,834	)		(30,850,004	)		(23,140,425	)
Other Income (Expense)		13,022			(169,308	)		45,794			(437,032	)
Total Other Income (Expense)		(10,611,224	)		(9,382,142	)		(30,804,210	)		(23,577,457	)

INCOME BEFORE INCOME TAXES		93,035,310			2,730,904			96,562,624			56,928,712

INCOME TAX PROVISION		35,050,000			1,028,000			36,400,000			21,262,614

NET INCOME	$	57,985,310		$	1,702,904		$	60,162,624		$	35,666,098

COMPREHENSIVE INCOME	$	57,985,310		$	1,702,904		$	60,162,624		$	35,666,098

Net Income Per Common Share – Basic	$	0.96		$	0.03		$	0.99		$	0.57
Net Income Per Common Share – Diluted	$	0.95		$	0.03		$	0.99		$	0.56
Weighted Average Shares Outstanding – Basic		60,559,827			62,426,341			60,753,752			62,750,952
Weighted Average Shares Outstanding – Diluted		60,736,502			62,758,378			60,950,641			63,142,238

	September 30, 2014 (unaudited)			December 31, 2013
CURRENT ASSETS
Cash and Cash Equivalents	$	8,049,167		$	5,687,166
Trade Receivables		88,575,478			86,816,981
Advances to Operators		869,485			618,786
Prepaid and Other Expenses		1,792,569			770,740
Derivative Instruments		3,849,629			62,890
Deferred Tax Asset		3,312,000			10,431,000
Total Current Assets		106,448,328			104,387,563

PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved		2,005,625,094			1,611,073,747
Unproved		71,275,756			70,148,348
Other Property and Equipment		1,781,645			1,701,366
Total Property and Equipment		2,078,682,495			1,682,923,461
Less – Accumulated Depreciation and Depletion		(409,239,931	)		(285,616,752	)
Total Property and Equipment, Net		1,669,442,564			1,397,306,709

DERIVATIVE INSTRUMENTS		6,142,424			1,745,405

DEBT ISSUANCE COSTS		14,541,339			16,160,283

TOTAL ASSETS	$	1,796,574,655		$	1,519,599,960

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	220,127,572		$	168,936,785
Accrued Expenses		4,933,500			2,645,178
Accrued Interest		13,491,862			3,386,409
Derivative Instruments		531,246			19,119,646
Total Current Liabilities		239,084,180			194,088,018

LONG-TERM LIABILITIES
Revolving Credit Facility		228,000,000			75,000,000
8% Senior Notes		508,424,779			509,539,823
Derivative Instruments		1,975,681			637,208
Other Noncurrent Liabilities		4,824,408			3,832,550
Deferred Tax Liability		145,955,000			116,674,000
Total Long-Term Liabilities		889,179,868			705,683,581

TOTAL LIABILITIES		1,128,264,048			899,771,599

COMMITMENTS AND CONTINGENCIES (NOTE 8)

STOCKHOLDERS’ EQUITY
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding		-			-
Common Stock, Par Value $.001; 95,000,000 Authorized, 9/30/2014 – 61,026,673 Shares Outstanding and 12/31/2013 – 61,858,199 Shares Outstanding		61,027			61,858
Additional Paid-In Capital		434,364,613			446,044,159
Retained Earnings		233,884,967			173,722,344
Total Stockholders’ Equity		668,310,607			619,828,361

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,796,574,655		$	1,519,599,960

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
Net Income	$	57,985,310		$	1,702,904	$	60,162,624		$	35,666,098
Add:
(Gain) Loss on the Mark-to-Market of Derivative Instruments, Net of Tax		(42,738,361	)		18,308,197		(15,845,185	)		17,074,790
Legal Settlements, Net of Tax		359,471			-		359,471			-
Adjusted Net Income	$	15,606,420		$	20,011,101	$	44,676,910		$	52,740,888

Weighted Average Shares Outstanding – Basic		60,559,827			62,426,341		60,753,752			62,750,952
Weighted Average Shares Outstanding – Diluted		60,736,502			62,758,378		60,950,641			63,142,238

Net Income Per Common Share - Basic	$	0.96		$	0.03	$	0.99		$	0.57
Add:
Change due to (Gain) Loss on the Mark-to-Market of Derivative Instruments, Net of Tax		(0.71	)		0.29		(0.26	)		0.27
Change due to Legal Settlements, Net of Tax		0.01			-		0.01			-
Adjusted Net Income Per Common Share – Basic	$	0.26		$	0.32	$	0.74		$	0.84

Net Income Per Common Share – Diluted	$	0.95		$	0.03	$	0.99		$	0.56
Add:
Change due to (Gain) Loss on the Mark-to-Market of Derivative Instruments, Net of Tax		(0.70	)		0.29		(0.26	)		0.27
Change due to Legal Settlements, Net of Tax		0.01			-		0.01			-
Adjusted Net Income Per Common Share – Diluted	$	0.26		$	0.32	$	0.74		$	0.83

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
Net Income	$	57,985,310		$	1,702,904	$	60,162,624		$	35,666,098
Add:
Interest Expense		10,624,246			9,212,834		30,850,004			23,140,425
Income Tax Provision		35,050,000			1,028,000		36,400,000			21,262,614
Depreciation, Depletion, Amortization and Accretion		45,646,232			32,103,607		123,959,402			85,455,425
Non-Cash Share Based Compensation		736,971			1,239,623		2,022,180			3,547,493
(Gain) Loss on the Mark-to-Market of Derivative Instruments		(68,600,900	)		29,353,161		(25,433,684	)		27,254,147
Adjusted EBITDA	$	81,441,859		$	74,640,129	$	227,960,526		$	196,326,202

County	Gross Wells		Net Wells		Percentage of Total
Mountrail		104		6.8		27	%
McKenzie		100		7.4		30	%
Williams		82		6.6		26	%
Dunn		47		2.4		10	%
Other		26		1.8		7	%
Total		359		25.0		100	%