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NOG > SEC Filings for NOG > Form 10-Q on 7-May-2013All Recent SEC Filings

Show all filings for NORTHERN OIL & GAS, INC. | Request a Trial to NEW EDGAR Online Pro

Form 10-Q for NORTHERN OIL & GAS, INC.


7-May-2013

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Cautionary Statement Concerning Forward-Looking Statements

This Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding future events and our 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 report regarding our 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 report, 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 our Company's control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: crude oil and natural gas prices, our ability to raise or access capital, general economic or industry conditions, nationally and/or in the communities in which our Company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, 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 our Company's operations, products and prices.

We have based any forward-looking statements on our current expectations and assumptions about future events. While our 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 our control. Accordingly, results actually achieved may differ materially from expected results described in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in the section entitled "Item 1A. Risk Factors" and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2012, as updated by subsequent reports we file with the SEC (including this report), which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.

The following discussion should be read in conjunction with the Financial Statements and Accompanying Notes appearing elsewhere in this report.

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties, primarily in the Bakken and Three Forks formations within the Williston Basin in North Dakota and Montana. We believe the location, size and concentration of our acreage position in one of North America's leading unconventional oil-resource plays will provide drilling and development opportunities that result in significant long-term value. Our primary focus is oil exploration and production through non-operated working interests in wells drilled and completed in spacing units that include our acreage.

As of December 31, 2012, our proved reserves were 67.6 MMBoe (all of which were in the Williston Basin) as estimated by Ryder Scott, our independent reservoir engineering firm, representing a 44% growth in proved reserves compared to year end 2011. As of December 31, 2012, 45% of our reserves were classified as proved developed and 90% of our reserves were oil.


Our average daily production in the first quarter of 2013 was approximately 11,115 Boe per day, of which approximately 90% was oil. Our first quarter 2013 average daily production increased 30% year-over-year, as compared to an average of 8,517 Boe per day in the first quarter of 2012. As of March 31, 2013, we participated in 1,355 gross (115.8 net) producing wells.

As of March 31, 2013, we leased approximately 676,532 gross (181,823 net) acres, of which 100% were located in the Williston Basin of North Dakota and Montana. In 2012, we acquired or earned through farm-in arrangements approximately 17,590 net mineral acres at an average cost of approximately $1,788 per net acre. During the quarter ended March 31, 2013, we acquired approximately 6,022 net mineral acres at an average cost of approximately $1,087 per net acre.

Highlights from First Quarter 2013 Results

During the three months ended March 31, 2013, we achieved the following financial and operating results:

Including the effect of realized losses from derivative contracts, oil, gas and NGL sales increased 38% for the three month period ended March 31, 2013 as compared to the same period last year;

Average daily production reached 11,115 Boe per day;

Participated in the completion of 128 gross (9.6 net) wells

Entered into additional derivative contracts for 2013, 2014 and 2015; and

Increased the borrowing base under our revolving credit facility from $350 million to $400 million.

Total oil, gas, and NGL sales increased 28% for the first quarter of 2013 compared to the same period in 2012. This increase was due to higher production levels resulting from the addition of 9.6 net wells added in the first quarter of 2013. Average realized prices on a per Boe basis (including realized gains (losses) from derivative contracts) were 7% higher in the first quarter of 2013 compared to the same period in 2012.

Source of Our Revenues

We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements. Our average realized price calculations include the effects of the settlement of all derivative contracts regardless of the accounting treatment.

Principal Components of Our Cost Structure

Oil price differentials. The price differential between our Williston Basin well head price and the NYMEX WTI benchmark price is driven by the additional cost to transport oil from the Williston Basin via train, barge, pipeline or truck to refineries.

Unrealized gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil. This account activity represents the recognition of gains and losses associated with our outstanding derivative contracts as commodity prices and commodity derivative contracts change on contracts that have not been designated for hedge accounting.

Realized gain (loss) on derivative instruments. This account activity represents our realized gains and losses on the settlement of commodity derivative instruments.


Production expenses. Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.

Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

Depreciation, depletion and amortization. Depreciation, depletion and amortization includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method.

General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.

Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our full cost pool. We include interest expense that is not capitalized into the full cost pool, the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees as interest expense.

Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

the timing and success of drilling and production activities by our operating partners;

the prices and demand for oil, natural gas and NGLs;

the quantity of oil and natural gas production from the wells in which we participate;

changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil;

our ability to continue to identify and acquire high-quality acreage; and

the level of our operating expenses.

In addition to the factors that affect companies in our industry generally, the location of our acreage and wells in the Williston Basin subjects our operating results to factors specific to this region. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter months, and the limitations of the developing infrastructure and transportation capacity in this region.


The price of oil in the Williston Basin can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market. Light sweet crude from the Williston Basin has a higher value at many major refining centers because of its higher quality relative to heavier and sour grades of crude oil; however, because of North Dakota's location relative to traditional oil transport centers, this higher value is generally offset to some extent by higher transportation costs. While rail transportation has historically been more expensive than pipeline transportation, Williston Basin prices have been high enough to justify shipment by rail to markets as far as St. James, Louisiana, which offers prices benchmarked to Brent/LLS. Although pipeline, truck and rail capacity in the Williston Basin has historically lagged production in growth, we believe that additional planned infrastructure growth will help keep price discounts from significantly eroding wellhead values in the region.

The price at which our oil production is sold typically reflects a discount to the NYMEX WTI benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the NYMEX WTI and the sales prices we receive for our oil production. Lower oil price differentials increased our oil and gas sales in the first quarter of 2013 as compared to the first quarter of 2012. Relatively mild weather in North Dakota in the winter of 2011-2012 allowed production throughout the winter (increasing supply) while some refineries were down for routine maintenance (decreasing demand). This caused oil price differentials to increase for a short period during the first half of 2012, which have subsequently declined to more typical historical levels due to various rail projects coming online, refineries completing their seasonal maintenance and the reversal of the Seaway pipeline from Cushing, Oklahoma to the Gulf Coast. Our oil price differential to the NYMEX WTI benchmark price during the first quarter of 2013 was $3.62 per barrel, as compared to $14.09 per barrel in the first quarter of 2012.

Another significant factor affecting our operating results is drilling costs. The cost of drilling wells has increased significantly over the past few years as rising oil prices have triggered increased drilling activity in the Williston Basin. Although individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the choice of proppant (sand or ceramic), the total cost of drilling and completing an oil well has increased. This increase is largely due to longer horizontal laterals and more fracture stimulation stages, but also higher demand for rigs and completion services throughout the region. In addition, because of the rapid growth in drilling, the availability of well completion services has at times been constrained, resulting at times in a backlog of wells that are awaiting completion.

Market Conditions

Prices for various quantities of natural gas, natural gas liquids ("NGLs") and
oil that we produce significantly impact our revenues and cash flows. Commodity
prices have been volatile in recent years. The following table lists average New
York Mercantile Exchange ("NYMEX") prices for natural gas and oil for the three
months ended March 31, 2013 and 2012.

                            Three Months Ended
                                 March 31,
                            2013           2012
Average NYMEX prices(a)
Natural gas (per mcf)     $    3.48      $   2.50
Oil (per bbl)             $   94.36      $ 103.03


________________


(a) Based on average NYMEX closing prices.

Results of Operations for the periods ended March 31, 2013 and March 31, 2012

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


                                                                  Three Months Ended
                                                                       March 31,
                                                         2013              2012          % Change
Net Production:
Oil (Bbl)                                                  902,738          717,518             26 %
Natural Gas and NGLs (Mcf)                                 585,412          345,427             69
Total (Boe)                                              1,000,306          775,089             29

Net Sales:
Oil Sales                                            $  80,007,563     $ 62,674,342             28
Natural Gas and NGL Sales                                3,164,098        2,465,054             28
Loss on Settled Derivatives                               (371,283 )     (5,335,597 )          (93 )
Unrealized Loss on Derivative Instruments              (14,910,655 )     (9,364,913 )           59
Other Revenue                                                8,359           84,106            (90 )
Total Revenues                                          67,898,082       50,522,992             34

Average Sales Prices:
Oil (per Bbl)                                        $       88.63     $      87.35              1
Effect of Loss on Settled Derivatives on Average
Price (per Bbl)                                              (0.41 )          (7.44 )          (94 )
Oil Net of Settled Derivatives (per Bbl)                     88.22            79.91             10
Natural Gas and NGLs (per Mcf)                                5.40             7.14            (24 )
Realized price on a Boe basis including all
realized derivative settlements                              82.78            77.16              7

Operating Expenses:
Production Expenses                                  $   8,641,210     $  6,513,348             33
Production Taxes                                         7,811,304        6,078,885             28
General and Administrative Expense
(Including Non-Cash Share Based Compensation)            3,988,806        4,681,378            (15 )
Depletion of Oil and Gas Properties                     26,668,171       18,309,500             46

Costs and Expenses (per Boe):
Production Expenses                                  $        8.64     $       8.40              3
Production Taxes                                              7.81             7.84              0
General and Administrative Expense
(Including Non-Cash Share Based Compensation)                 3.99             6.04            (34 )
Depletion of Oil and Gas Properties                          26.66            23.62             13

Net Producing Wells at Period End                            115.8             71.8             61

Oil and Natural Gas Sales

In the first quarter of 2013, oil, natural gas and NGL sales increased 28% as compared to the first quarter of 2012, driven primarily by a 29% increase in production and partially aided by an 7% increase in realized prices taking into account the effect of settled derivatives. In addition, the higher average realized price in the first quarter of 2013 as compared to the same period in 2012 was driven by a lower oil differential. Oil differential during the first quarter of 2013 was $3.62 per barrel, as compared to $14.09 per barrel in the first quarter of 2012.

As discussed above, our production continues to grow through drilling success as we place new wells into production and through additions from acquisitions, partially offset by the natural decline of our oil and natural gas sales from existing wells. During the first quarter of 2013, our production volumes increased 29% as compared to the first quarter of 2012. Production primarily increased due to our continued addition of net producing wells.


Derivative Instruments

For the three months ended March 31, 2013, we incurred a loss on settled derivatives of $0.4 million, compared to a $5.3 million loss for the three months ended March 31, 2012. Our average realized price (including all derivative settlements) received during the first quarter of 2013 was $82.78 per Boe compared to $77.16 per Boe in the first quarter of 2012. Our average realized price (including all derivative settlements) calculation includes all cash settlements for derivatives.

We had mark-to-market derivative losses of $14.9 million in the first quarter of 2013 compared to a $9.4 million loss in the first quarter of 2012. At March 31, 2013, all of our derivative contracts were recorded at their fair value, which was a net liability of $11.6 million, a decrease of $9.6 million from the $21.2 million net liability recorded as of March 31, 2012.

Production Expenses

Production expenses were $8.6 million in the first quarter of 2013 compared to $6.5 million in the first quarter of 2012. We experience increases in operating expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses per Boe increased from $8.40 per barrel sold in the first quarter of 2012 to $8.64 in first quarter of 2013. The largest cost driver in our Williston Basin operations is the disposal of water. On an absolute dollar basis, our production expenses in the first quarter of 2013 were 33% higher when compared to the same quarter in 2012 due to production levels increasing 29%, higher water hauling and disposal costs and workover expenses.

Production Taxes

We pay production taxes based on realized crude oil and natural gas sales. These costs were $7.8 million in the first quarter of 2013 compared to $6.1 million in the first quarter of 2012. As a percent of oil and natural gas sales, our production taxes were 9.4% and 9.3% in the three month periods ended 2013 and 2012, respectively. The 2013 average production tax rate was higher than the 2012 average due to fewer well additions that qualified for reduced rates/or tax exemptions during 2013. Certain of our production is in Montana and North Dakota jurisdictions that have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate.

General and Administrative Expense

General and administrative expense was $4.0 million for the first quarter of 2013 compared to $4.7 million for the first quarter of 2012. The 2013 decrease of $0.7 million when compared to 2012 was primarily due to a decrease in share based compensation ($1.1 million), partially offset by increased salaries and benefits ($0.3 million) and increased travel expense ($0.1 million).

Depletion, Depreciation and Amortization

Depletion, depreciation and amortization ("DD&A") was $26.8 million in the first quarter of 2013 compared to $18.4 million in the first quarter of 2012. Depletion expense, the largest component of DD&A, was $26.66 per Boe in the first quarter of 2013 compared to $23.62 per Boe in the first quarter of 2012. The aggregate increase in depletion expense for 2013 compared to 2012 was driven by a 29% increase in production. Additionally, depletion rates rose in 2013 due to an increase in our future development cost estimates to reflect the changes in well completion methodologies (e.g. more stimulation costs per well due to longer lateral extensions). Depletion rates in new plays tend to be higher in the beginning as increased initial outlays are amortized over proved reserves based on early stages of evaluations. As these plays mature, new technologies, well completion methodologies and additional historical operating information impact the reserve evaluations. Depreciation, amortization and accretion was $0.1 million in first quarter of 2013 compared to $0.1 million in the first quarter of 2012. The following table summarizes DD&A expense per Boe for the first quarters of 2013 and 2012:


                                                        Three Months Ended
                                                            March 31,
                                            2013        2012       Change        Change
Depletion                                   $ 26.66     $ 23.62     $  3.04           13 %
Depreciation, amortization, and accretion      0.12        0.15       (0.03 )        (20 %)
Total DD&A expense                          $ 26.78     $ 23.77     $  3.01           13 %

Interest Expense

Interest expense, net of capitalized interest, was $6.1 million for the first quarter of 2013 compared to $0.2 million in the first quarter of 2012. The increase in interest expense was due to the higher rate of interest on our 8.000% senior unsecured notes due 2020, which were outstanding during the first quarter of 2013 but not the first quarter of 2012.

Income Tax Provision

The provision for income taxes was $5.6 million in the first quarter of 2013 compared to $5.8 million in the first quarter of 2012. The effective tax rate in 2013 was 38.5% compared to an effective tax rate of 39.8% in 2012.The effective tax rate was different than the statutory rate of 35% primarily due to state tax rates.

Non-GAAP Financial Measures

We define Adjusted Net Income as net income excluding unrealized gain (loss) on derivative instruments, net of tax. Our Adjusted Net Income for the first quarter of 2013 was $18.1 million (representing approximately $0.29 per diluted share), compared to $14.4 million (representing approximately $0.23 per diluted share) for the first quarter of 2012. The increase in non-GAAP net income is primarily due to our continued addition of crude oil and natural gas production from new wells and higher realized commodity prices in 2013 compared to 2012.

We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) unrealized gain (loss) on derivative instruments and (v) non-cash share based compensation expense. Adjusted EBITDA for the first quarter of 2013 was $63.5 million, compared to Adjusted EBITDA of $44.8 million for the first quarter of 2012. The increase in Adjusted EBITDA is primarily due to our continued addition of crude oil and natural gas production from new wells and higher realized commodity prices in 2013 compared to 2012.

We believe the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of our current financial performance. Specifically, we believe 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 our management believes are not indicative of our core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring our performance, and we believe that we are providing investors with financial measures that most closely align to our internal measurement processes. We consider these non-GAAP measures to be useful in evaluating our core operating results as they more closely reflect our essential revenue generating activities and direct operating . . .

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