Northern Oil and Gas, Inc. Announces 2013 Fourth Quarter and Full Year Results
WAYZATA, MINNESOTA — February 27, 2014 — Northern Oil and Gas, Inc. (NYSE MKT: NOG) today announced fourth quarter and full year results, year-end proved reserves, and 2014 production and capital budget guidance.
2013 HIGHLIGHTS
| · | Annual production increased 19% to 4,475,409 barrels of oil equivalent (“Boe”), or 12,261 average Boe per day |
| · | Fourth quarter production increased 28% year-over-year to 13,946 average Boe per day |
| · | 2013 oil and gas sales increased 24% to $369.2 million |
| · | Proved reserves increased 25% to 84.2 million Boe and pre-tax PV-10 increased 18% to $1.5 billion, achieving a reserve replacement ratio of 370% |
| · | Added 531gross (40.0 net) wells to production bringing total producing wells to 1,758 gross (146.2 net) |
| · | Currently participating in an additional 252 gross (18.8 net) wells drilling or awaiting completion as of January 31, 2014 |
| · | Company repurchased 2,036,383 shares of its common stock at an average price of $12.82 per share |
“Northern experienced robust production growth in the second half of 2013, growing production 25% over the first half of 2013,” commented Northern’s Chairman and Chief Executive Officer Michael Reger. “We finished 2013 with solid momentum as fourth quarter production grew 28% year-over-year. Looking at the beginning of 2014, due to abnormally severe winter weather and expected road weight restrictions, net well additions may slow in the first half of this year. However, we remain confident in achieving our objectives for full year 2014 due to the increase in wells in process and expected acceleration in the second half of 2014. Overall, we expect to see the economics of the basin improving as operators are increasingly focused on full pad development drilling and optimizing completion design, which should continue to improve productivity in 2014.”
RESULTS OF OPERATIONS FOR 2013
The following table summarizes the full year operating and financial results for 2013 as compared to 2012:
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | | | Change | |
| Net Production: | | | | | | | | | |
| Oil (Bbl) | | | 4,046,701 | | | | 3,465,311 | | | | 17 | % |
| Natural Gas and NGLs (Mcf) | | | 2,572,251 | | | | 1,768,872 | | | | 45 | % |
| Total (Boe) | | | 4,475,409 | | | | 3,760,123 | | | | 19 | % |
| | | | | | | | | | | | | |
| Average Daily Production: | | | | | | | | | | | | |
| Oil (Bbl) | | | 11,087 | | | | 9,468 | | | | 17 | % |
| Natural Gas and NGLs (Mcf) | | | 7,047 | | | | 4,833 | | | | 46 | % |
| Total (Boe) | | | 12,261 | | | | 10,274 | | | | 19 | % |
| | | | | | | | | | | | | |
| Average Sales Prices: | | | | | | | | | | | | |
| Oil (per Bbl) | | $ | 87.90 | | | $ | 83.22 | | | | 6 | % |
| Effect of loss on settled derivatives (per Bbl) | | | (3.01 | ) | | | (0.11 | ) | | | | |
| Oil net of settled derivatives (per Bbl) | | | 84.89 | | | | 83.11 | | | | 2 | % |
| Natural Gas and NGLs (per Mcf) | | | 5.24 | | | | 4.67 | | | | 12 | % |
Realized price per Boe(a) | | | 79.77 | | | | 78.79 | | | | 1 | % |
| | | | | | | | | | | | | |
| Average Production Costs (per Boe of production): | | | | | | | | | | | | |
| Production Expenses | | $ | 9.35 | | | $ | 8.61 | | | | 9 | % |
| Production Taxes | | | 7.81 | | | | 7.58 | | | | 3 | % |
| General and Administrative Expense | | | 3.70 | | | | 6.02 | | | | (39 | )% |
| Depletion, Depreciation, Amortization and Accretion | | | 27.79 | | | | 26.31 | | | | 6 | % |
| | | | | | | | | | | | | |
| (a) | Realized prices include realized gains or losses on cash settlements for commodity derivatives. |
In 2013, oil, natural gas and natural gas liquids (“NGL”) sales, including the effect of settled derivatives, increased 21% from 2012 to $357 million, driven by average production of 12,261 Boe per day, a 19% increase year-over-year. Northern’s average oil price differential to the NYMEX WTI benchmark during 2013 was $8.68 per barrel, as compared to $9.79 per barrel in 2012.
As a result of oil price derivative activities, Northern incurred a net cash settlement loss of $12.2 million in 2013, compared to a loss of $0.4 million in 2012. As a result of forward oil price changes, mark-to-market derivative gains and losses resulted in a non-cash loss of $21.3 million in 2013 compared to a non-cash gain of $15.1 million in 2012.
Production expenses were $41.9 million in 2013, compared to $32.4 million in 2012. Northern experiences an increase in aggregate operating expenses as it adds new wells and maintains production from existing properties. On a per unit basis, the average production expenses per Boe increased from $8.61 per barrel in 2012 to $9.35 in 2013. The year-over-year increase on a per unit basis is primarily due to increased costs associated with water hauling, water disposal and workovers.
Northern pays production taxes based on realized oil and natural gas sales. These costs were $35.0 million in 2013, compared to $28.5 million in 2012. Average production tax rates were 9.5% and 9.6% in 2013 and 2012, respectively. The 2013 average production tax rate was slightly lower than the 2012 average due to additional wells that qualified for reduced rates or tax exemptions during 2013.
General and administrative expense was $16.6 million for 2013 compared to $22.6 million for 2012. The 2013 decrease of $6.0 million when compared to 2012 is primarily due to a $5.5 million severance charge recognized in 2012 in connection with the departures of the Company’s former president and former chief operating officer during 2012.
Depletion, depreciation, amortization and accretion (“DD&A”) was $124.4 million in 2013, compared to $98.9 million in 2012. The increase in aggregate DD&A expense for 2013 compared to 2012 was driven by a 19% increase in production, as well as a higher average depletion rate per Boe. Depletion expense, the largest component of DD&A, averaged $27.62 per Boe in 2013, compared to $26.18 per Boe in 2012.
The provision for income taxes was $31.8 million in 2013, compared to $43.0 million in 2012. The effective tax rate in 2013 was 37.4%, compared to an effective tax rate of 37.3% in 2012.
Net income was $53.1 million in 2013, compared to $72.3 million in 2012. The decrease in net income was driven by 2013 losses on settled derivatives and losses on the mark-to-market of derivative instruments. Additionally, the higher oil and gas revenues in 2013 were partially offset by increased production expenses, production taxes, depletion expenses, and interest expense in 2013 compared to 2012. Diluted net income per common share was $0.85 in 2013, compared to $1.15 in 2012.
Adjusted Net Income for 2013 was $66.4 million, or $1.06 per diluted share, as compared to $66.2 million, or $1.05 per diluted share, for 2012. Northern defines Adjusted Net Income as net income excluding (i) loss (gain) on the mark-to-market of derivative instruments, net of tax and (ii) severance expenses in connection with the 2012 departures of Northern’s former president and former chief operating officer, net of tax.
Adjusted EBITDA for 2013 was $268.0 million, which represents a 19% increase over Adjusted EBITDA of $225.3 million for 2012. Northern defines Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) loss (gain) 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 their 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.
FOURTH QUARTER 2013
The following tables summarize Northern’s fourth quarter operating and financial results for 2013 as compared to 2012:
| | | Quarter Ended December 31, | |
| | | 2013 | | | 2012 | | | Change | |
| Net Production: | | | | | | | | | |
| Oil (Bbl) | | | 1,155,495 | | | | 909,317 | | | | 27 | % |
| Natural Gas and NGLs (Mcf) | | | 765,154 | | | | 541,659 | | | | 41 | % |
| Total (Boe) | | | 1,283,021 | | | | 999,593 | | | | 28 | % |
| | | | | | | | | | | | | |
| Average Daily Production: | | | | | | | | | | | | |
| Oil (Bbl) | | | 12,560 | | | | 9,884 | | | | 27 | % |
| Natural Gas and NGLs (Mcf) | | | 8,317 | | | | 5,888 | | | | 41 | % |
| Total (Boe) | | | 13,946 | | | | 10,865 | | | | 28 | % |
| | | | | | | | | | | | | |
| Average Sales Prices: | | | | | | | | | | | | |
| Oil (per Bbl) | | $ | 82.35 | | | $ | 85.86 | | | | (4 | )% |
| Effect of (loss) gain on settled derivatives (per Bbl) | | | (2.80 | ) | | | 4.77 | | | | (159 | )% |
| Oil net of settled derivatives (per Bbl) | | | 79.55 | | | | 90.63 | | | | (12 | )% |
| Natural Gas and NGLs (per Mcf) | | | 5.23 | | | | 4.23 | | | | 24 | % |
Realized price per Boe(a) | | | 74.77 | | | | 84.74 | | | | (12 | )% |
| | | | | | | | | | | | | |
| Average Production Costs (per Boe of production): | | | | | | | | | | | | |
| Production Expenses | | $ | 8.85 | | | $ | 9.85 | | | | (10 | )% |
| Production Taxes | | | 7.53 | | | | 7.66 | | | | (2 | )% |
| General and Administrative Expense | | | 3.51 | | | | 4.08 | | | | (14 | )% |
| Depletion, Depreciation, Amortization and Accretion | | | 30.34 | | | | 26.79 | | | | 13 | % |
| | | | | | | | | | | | | |
| (a) | Realized prices include realized gains or losses on cash settlements for commodity derivatives. |
In the fourth quarter of 2013, oil, natural gas and NGL sales, including the effect of settled derivatives, increased 13% year-over-year to $95.9 million, driven by average production of 13,946 Boe per day, a 28% increase in production year-over-year and approximately 7% sequentially. Northern’s oil price differential to the NYMEX WTI benchmark during the fourth quarter of 2013 was $14.98 per barrel, as compared to $2.17 per barrel in the fourth quarter of 2012.
As a result of derivative activities, Northern incurred a net cash settlement loss of $3.2 million in the fourth quarter of 2013, compared to a gain of $4.3 million in the fourth quarter of 2012. As a result of forward oil price changes, mark-to-market derivative gains and losses were non-cash gains of $6.0 million in the fourth quarter of 2013 compared to non-cash losses of $3.0 million in the fourth quarter of 2012.
Production expenses were $11.4 million in the fourth quarter of 2013 compared to $9.8 million in the fourth quarter of 2012. Northern experiences an increase in aggregate operating expenses as it adds new wells and maintains production from existing properties. On a per unit basis, production expenses per Boe decreased from $9.85 per barrel sold in the fourth quarter of 2012 to $8.85 in the fourth quarter of 2013. The decreased cost on a per unit basis is primarily due to increased production from lower cost areas in the fourth quarter of 2013 as compared to the fourth quarter of 2012.
Northern pays production taxes based on realized oil and gas sales. These costs were $9.7 million in the fourth quarter of 2013, compared to $7.7 million in the fourth quarter of 2012. Average production tax rates were 9.7% in the fourth quarter of 2013 and 9.5% in the fourth quarter of 2012. The 2013 average production tax rate was higher than the 2012 average due to fewer wells that qualified for reduced rates or tax exemptions during 2013.
General and administrative expense was $4.5 million for the fourth quarter of 2013, compared to $4.1 million for the fourth quarter of 2012. The fourth quarter of 2013 increase over the fourth quarter of 2012 was primarily driven by increased insurance costs and professional service expenses.
DD&A was $38.9 million in the fourth quarter of 2013, compared to $26.8 million in the fourth quarter of 2012. The increase in aggregate DD&A expense for the fourth quarter of 2013 compared to the fourth quarter of 2012 was driven by a 28% increase in production and 13% increase in the DD&A rate per Boe. Depletion expense, the largest component of DD&A, was $30.02 per Boe in the fourth quarter of 2013, compared to $26.66 per Boe in the fourth quarter of 2012. Northern’s depletion rate for the fourth quarter was adjusted in connection with completion of Northern’s 2013 year-end reserve report, and the depletion rate rose in 2013 primarily due to higher production expenses and revised reserve estimates in certain areas of the Company’s operations.
Net income was $17.4 million in the fourth quarter of 2013, compared to $19.6 million in the fourth quarter of 2012. Diluted net income per common share decreased to $0.28 in the fourth quarter of 2013, compared to $0.31 in the fourth quarter of 2012.
Adjusted Net Income for the fourth quarter of 2013 was $13.7 million, or $0.22 per diluted share, as compared to $21.4 million, or $0.34 per diluted share, for the fourth quarter of 2012. Northern defines Adjusted Net Income as net income excluding (i) loss (gain) on the mark-to-market of derivative instruments, net of tax and (ii) severance expenses in connection with the 2012 departures of Northern’s former president and former chief operating officer, net of tax.
Northern’s Adjusted EBITDA for the fourth quarter of 2013 was $71.7 million, which represents a 12% increase over Adjusted EBITDA of $64.3 million for the fourth quarter of 2012. Northern defines Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) (loss) gain 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.
ACREAGE AND DRILLING UPDATE
As of December 31, 2013, Northern controlled approximately 187,044 net acres targeting the Williston Basin Bakken and Three Forks. In 2013, Northern acquired leasehold interests covering an aggregate of approximately 20,900 net mineral acres in its key prospect areas, for an average cost of $1,279 per net acre. In the fourth quarter of 2013, Northern acquired leasehold interests covering an aggregate of approximately 3,046 net mineral acres in its key prospect areas, for an average cost of $1,543 per net acre.
As of December 31, 2013, approximately 63% of Northern’s total acreage position, and approximately 73% of Northern’s North Dakota acreage position, was developed, held by production or held by operations.
In 2013, Northern spud approximately 42.8 net wells and added 40.0 net wells to production. Northern added 12.6 net wells to production in the fourth quarter of 2013.
During January 2014, Northern added 0.9 net wells to production and the number of wells drilling or waiting completion at the end of the month increased to 252 gross (18.8 net) wells.
CAPITAL EXPENDITURES
During 2013, Northern’s acquisition and development expenditures included approximately $389.5 million of drilling, completion and capitalized workover costs, and $11.1 million of capitalized interest and other. Also in 2013, approximately $38.5 million was expended on acreage and other expenditures in the Williston Basin, resulting in total capital expenditures of $439.1 million for 2013.
LIQUIDITY UPDATE
Northern ended the year with $75 million drawn on its revolving credit facility, which has a total borrowing capacity of $450 million. Northern also ended the year with $6 million in cash, resulting in liquidity of approximately $381 million.
CAPITAL PROGRAM AND PRODUCTION GUIDANCE FOR 2014
Northern expects 2014 total capital expenditures to range between $430 million and $440 million. The company expects current liquidity, as outlined above, and cash flow from operations to meet its capital expenditure needs for 2014. The total capital budget includes approximately:
| · | $400 million in drilling and completions expense, which includes approximately $12 million in capitalized workover expenses for the year |
| · | $30 million to $40 million on acreage and other expenditures |
The 2014 budget anticipates the Company will participate in the drilling and completion of approximately 44 net wells targeting the Bakken and Three Forks formations. Northern expects the average well cost to be approximately $8.8 million per well for 2014.
Based on the assumed net well additions outlined above, Northern estimates 2014 production growth of approximately 15% over 2013 levels, resulting in 2014 production of approximately 5.1 million barrels of oil equivalent.
2013 YEAR-END RESERVES
Based on reports prepared by Ryder Scott Company, L.P., Northern’s estimated total proved reserves at December 31, 2013 were approximately 84.2 million barrels of oil equivalent (MMBoe), a 25% increase as compared to 67.6 MMBoe at December 31, 2012. Pre-Tax PV10 of the proved reserves as of December 31, 2013 is approximately $1.5 billion. The year-over-year increase in reserves relative to Northern’s 2013 production reflects a reserve replacement ratio of 370%. Approximately 42% of Northern’s reserves at December 31, 2013 are categorized as proved developed, and the remaining 58% are classified as proved undeveloped.
Additional information regarding Northern’s proved reserves, including estimated future cash flows, discounted at an annual rate of 10 percent before giving effect to income taxes (commonly known as Pre-Tax PV10 value, which may be considered a non-GAAP measure), is attached at the end of this release.
HEDGING UPDATE
The following table reflects the weighted average price of Northern’s open commodity swap derivative contracts as of December 31, 2013, by year with associated volumes.
Weighted Average Price Of Open Commodity Swap Contracts | |
| Year | | Volumes (Bbl) | | | Weighted Average Price | |
| 2014 | | | 3,750,000 | | | $ | 90.46 | |
| 2015 | | | 2,880,000 | | | | 89.02 | |
In addition to the open commodity swap contracts, Northern has entered into costless collar contracts. The costless collars are used to establish floor and ceiling prices on anticipated crude oil production. There were no premiums paid or received by Northern related to the costless collar contracts. The following table reflects open costless collar contracts as of December 31, 2013.
| Term | | Oil (Barrels) | | | Floor/Ceiling Price | | Basis |
| Costless Collars – Crude Oil | | | | | | | |
| 01/01/14 – 12/31/14 | | | 240,000 | | | $ | 90.00/$99.05 | | NYMEX |
FOURTH QUARTER AND FULL-YEAR 2013 EARNINGS RELEASE TELECONFERENCE 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, February 28, 2014 at 9:00 a.m. Central Standard Time. Details for the conference call are as follows:
Dial-In Number: 888-690-2899 (United States and Canada) and 913-312-1437 (International)
Conference ID: 8953312 - Northern Oil and Gas, Inc. Fourth Quarter and Year-End 2013 Earnings Call
Replay Dial-In Number: (888) 203-1112 (US/Canada) and (719) 457-0820 (International)
Replay Access Code: 8953312 - Replay will be available through Friday, March 14, 2014
UPCOMING CONFERENCE SCHEDULE
Wells Fargo Securities 5th Annual Exploration & Production 1x1 Forum
March 6th, 2014, Boston, MA
Northland Capital Markets 2014 Growth Conference
March 12, 2014, New York, NY
42st Annual Howard Weil Energy Conference
March 23 – March 27, 2014, New Orleans, LA
IPAA Oil and Gas Investment Symposium
April 7 – April 9, 2014, New York, NY
ABOUT NORTHERN OIL AND GAS, INC.
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,” “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.
INVESTOR RELATIONS CONTACT:
Brandon Elliott
EVP, Corporate Development and Strategy
952-476-9800
belliott@northernoil.com
Erik Nerhus
VP, Business Development
952-476-9800
enerhus@northernoil.com
NORTHERN OIL AND GAS, INC.
STATEMENTS OF COMPREHENSIVE INCOME
| | | Three Months Ended | | | Year Ended | |
| | | December 31, | | | December 31, | |
| | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
| REVENUES | | | | | | | | | | | | |
| Oil and Gas Sales | | $ | 99,160,226 | | | $ | 80,369,145 | | | $ | 369,187,120 | | | $ | 296,637,857 | |
| Loss on Settled Derivatives | | | (3,232,459 | ) | | | 4,337,766 | | | | (12,198,633 | ) | | | (391,420 | ) |
| (Losses) Gains on the Mark-to-Market of Derivative Instruments | | | 5,995,130 | | | | (2,978,806 | ) | | | (21,259,018 | ) | | | 15,147,122 | |
| Other Revenue | | | 6,888 | | | | 18,579 | | | | 44,402 | | | | 179,331 | |
| Total Revenue | | | 101,929,785 | | | | 81,746,684 | | | | 335,773,871 | | | | 311,572,890 | |
| | | | | | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | | | | | |
| Production Expenses | | | 11,348,887 | | | | 9,842,073 | | | | 41,859,135 | | | | 32,382,310 | |
| Production Taxes | | | 9,655,169 | | | | 7,655,862 | | | | 34,958,975 | | | | 28,485,594 | |
| General and Administrative Expense | | | 4,507,001 | | | | 4,076,619 | | | | 16,575,440 | | | | 22,645,315 | |
| Depletion, Depreciation, Amortization and Accretion | | | 38,927,949 | | | | 26,775,958 | | | | 124,383,374 | | | | 98,923,240 | |
| Total Expenses | | | 64,439,006 | | | | 48,350,512 | | | | 217,776,924 | | | | 182,436,459 | |
| | | | | | | | | | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | | | 37,490,778 | | | | 33,396,172 | | | | 117,996,947 | | | | 129,136,431 | |
| | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE) | | | | | | | | | | | | | | | | |
| Other Income (Expense) | | | (16,201 | ) | | | 23,668 | | | | (453,242 | ) | | | 24,874 | |
| Interest Expense, Net of Capitalization | | | (9,568,631 | ) | | | (5,744,684 | ) | | | (32,709,056 | ) | | | (13,874,909 | ) |
| Total Other Income (Expense) | | | (9,584,841 | ) | | | (5,721,016 | ) | | | (33,162,297 | ) | | | (13,850,035 | ) |
| | | | | | | | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | | 27,905,937 | | | | 27,675,156 | | | | 84,834,650 | | | | 115,286,396 | |
| | | | | | | | | | | | | | | | | |
| INCOME TAX PROVISION | | | 10,505,000 | | | | 8,123,000 | | | | 31,767,614 | | | | 43,001,772 | |
| | | | | | | | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | 17,400,937 | | | $ | 19,552,156 | | | $ | 53,067,036 | | | $ | 72,284,624 | |
| | | | | | | | | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME, NET OF TAX | | | | | | | | | | | | | | | | |
| Reclassification of Derivative Instruments included in Income (Net of Tax of $0 for the three months ended December 31, 2013 and 2012 and $0 and $39,000 for the years ended December 31, 2013 and 2012, respectively) | | | - | | | | - | | | | - | | | | 62,309 | |
| Total Other Comprehensive Income | | | - | | | | - | | | | - | | | | 62,309 | |
| | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | $ | 17,400,937 | | | $ | 19,552,156 | | | $ | 53,067,036 | | | $ | 72,346,933 | |
| | | | | | | | | | | | | | | | | |
| Net Income Per Common Share – Basic | | $ | 0.28 | | | $ | 0.31 | | | $ | 0.85 | | | $ | 1.16 | |
| Net Income Per Common Share – Diluted | | $ | 0.28 | | | $ | 0.31 | | | $ | 0.85 | | | $ | 1.15 | |
| Weighted Average Shares Outstanding – Basic | | | 61,219,556 | | | | 62,711,369 | | | | 62,364,957 | | | | 62,485,836 | |
| Weighted Average Shares Outstanding – Diluted | | | 61,575,358 | | | | 63,214,075 | | | | 62,747,298 | | | | 62,869,079 | |
NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
| | | December 31, | |
| | | 2013 | | | 2012 | |
| CURRENT ASSETS | | | | | | |
| Cash and Cash Equivalents | | $ | 5,687,166 | | | $ | 13,387,998 | |
| Trade Receivables | | | 86,816,981 | | | | 70,219,669 | |
| Advances to Operators | | | 618,786 | | | | 3,109,591 | |
| Prepaid and Other Expenses | | | 770,740 | | | | 1,707,089 | |
| Derivative Instruments | | | 62,890 | | | | 4,095,197 | |
| Deferred Tax Asset | | | 10,431,000 | | | | 1,695,000 | |
| Total Current Assets | | | 104,387,563 | | | | 94,214,544 | |
| | | | | | | | | |
| PROPERTY AND EQUIPMENT | | | | | | | | |
| Oil and Natural Gas Properties, Full Cost Method of Accounting | | | | | | | | |
| Proved | | | 1,611,073,747 | | | | 1,159,191,601 | |
| Unproved | | | 70,148,348 | | | | 82,926,384 | |
| Other Property and Equipment | | | 1,701,366 | | | | 3,158,224 | |
| Total Property and Equipment | | | 1,682,923,461 | | | | 1,245,276,209 | |
| Less - Accumulated Depreciation and Depletion | | | (285,616,752 | ) | | | 162,031,493 | |
| Total Property and Equipment, Net | | | 1,397,306,709 | | | | 1,083,244,716 | |
| | | | | | | | | |
| DERIVATIVE INSTRUMENTS | | | 1,745,405 | | | | 1,763,008 | |
| | | | | | | | | |
| DEBT ISSUANCE COSTS | | | 16,160,283 | | | | 11,713,030 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 1,519,599,960 | | | $ | 1,190,935,298 | |
| | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | |
| CURRENT LIABILITIES | | | | | | | | |
| Accounts Payable | | $ | 168,936,786 | | | $ | 95,822,162 | |
| Accrued Expenses | | | 2,645,178 | | | | 2,454,085 | |
| Accrued Interest | | | 3,386,409 | | | | 2,180,416 | |
| Derivative Instruments | | | 19,119,646 | | | | - | |
| Total Current Liabilities | | | 194,088,019 | | | | 100,456,663 | |
| | | | | | | | | |
| LONG-TERM LIABILITIES | | | | | | | | |
| Revolving Credit Facility | | | 75,000,000 | | | | 124,000,000 | |
| 8% Senior Notes Due 2020, Net of Accumulated Amortization of $960,177 and $0 at December 31, 2013 and 2012, respectively | | | 509,539,823 | | | | 300,000,000 | |
| Derivative Instruments | | | 637,208 | | | | 2,547,745 | |
| Other Noncurrent Liabilities | | | 3,832,550 | | | | 1,570,630 | |
| Deferred Tax Liability | | | 116,674,000 | | | | 76,175,000 | |
| Total Long-Term Liabilities | | | 705,683,581 | | | | 504,293,375 | |
| | | | | | | | | |
| TOTAL LIABILITIES | | | 899,771,599 | | | | 604,750,038 | |
| | | | | | | | | |
| COMMITMENTS AND CONTINGENCIES | | | | | | | | |
| | | | | | | | | |
| STOCKHOLDERS' EQUITY | | | | | | | | |
| Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding | | | - | | | | - | |
Common Stock, Par Value $.001; 95,000,000 Authorized (12/31/2013 – 61,858,199Shares Outstanding and 12/31/2012 – 63,532,622 Shares Outstanding) | | | 61,858 | | | | 63,532 | |
| Additional Paid-In Capital | | | 446,044,159 | | | | 465,466,420 | |
| Retained Earnings | | | 173,722,344 | | | | 120,655,308 | |
| Total Stockholders' Equity | | | 619,828,361 | | | | 586,185,260 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | | $ | 1,519,599,960 | | | $ | 1,190,935,298 | |
| | | | | | | | | |
| | | | | | | | | |
Northern Oil and Gas, Inc.
Reconciliation of Adjusted EBITDA
(UNAUDITED)
| | | Three Months Ended | | | Year Ended | |
| | | December 31, | | | December 31, | |
| | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
| | | (in thousands) | |
| Net Income (Loss) | | $ | 17,401 | | | $ | 19,552 | | | $ | 53,067 | | | $ | 72,285 | |
| Add Back: | | | | | | | | | | | | | | | | |
| Interest Expense | | | 9,569 | | | | 5,745 | | | | 32,709 | | | | 13,875 | |
| Income Tax Provision | | | 10,505 | | | | 8,123 | | | | 31,768 | | | | 43,002 | |
| Depreciation, Depletion, Amortization and Accretion | | | 38,928 | | | | 26,776 | | | | 124,383 | | | | 98,923 | |
| Non-Cash Share Based Compensation | | | 1,251 | | | | 1,086 | | | | 4,799 | | | | 12,382 | |
| Losses (Gains) on the Mark-to-Market of Derivative Instruments | | | (5,995 | ) | | | 2,979 | | | | 21,259 | | | | (15,147 | ) |
| Adjusted EBITDA | | $ | 71,659 | | | $ | 64,261 | | | $ | 267,985 | | | $ | 225,320 | |
NORTHERN OIL AND GAS, INC.
Reconciliation of GAAP Net Income to Adjusted Net Income
(UNAUDITED)
| | | Three Months Ended | | Year Ended | |
| | | December 31, | | December 31, | |
| | | 2013 | | | 2012 | | 2013 | | | 2012 | |
| | | (in thousands, except share and per common share data) | |
| | | | | | | | | | | | | |
| Net Income | | $ | 17,401 | | | $ | 19,552 | | | $ | 53,067 | | | $ | 72,285 | |
| Add: | | | | | | | | | | | | | | | | |
| Losses (Gains) on the Mark-to-Market of Derivative Instruments (a) | | | (3,738 | ) | | | 1,415 | | | | 13,300 | | | | (9,497 | ) |
| Severance Expense, Net of Tax (b) | | | - | | | | 470 | | | | - | | | | 3,425 | |
| Adjusted Net Income | | $ | 13,663 | | | $ | 21,437 | | | $ | 66,367 | | | $ | 66,213 | |
| | | | | | | | | | | | | | | | | |
| Weighted Average Shares Outstanding – Basic | | | 61,219,556 | | | | 62,711,369 | | | | 62,364,957 | | | | 62,485,836 | |
| Weighted Average Shares Outstanding – Diluted | | | 61,575,358 | | | | 63,214,075 | | | | 62,747,298 | | | | 62,869,079 | |
| | | | | | | | | | | | | | | | | |
| Net Income Per Common Share – Basic | | $ | 0.28 | | | $ | 0.31 | | | $ | 0.85 | | | $ | 1.16 | |
| Add: | | | | | | | | | | | | | | | | |
| Change due to Losses (Gains) on the Mark-to-Market of Derivative Instruments, Net of Tax | | | (0.06 | ) | | | 0.02 | | | | 0.21 | | | | (0.15 | ) |
| Change due to Severance Expense, Net of Tax | | | - | | | | 0.01 | | | | - | | | | 0.05 | |
| Adjusted Net Income Per Common Share – Basic | | $ | 0.22 | | | $ | 0.34 | | | $ | 1.06 | | | $ | 1.06 | |
| | | | | | | | | | | | | | | | | |
| Net Income Per Common Share – Diluted | | $ | 0.28 | | | $ | 0.31 | | | $ | 0.85 | | | $ | 1.15 | |
| Add: | | | | | | | | | | | | | | | | |
| Change due to Losses (Gains) on the Mark-to-Market of Derivative Instruments, Net of Tax | | | (0.06 | ) | | | 0.02 | | | | 0.21 | | | | (0.15 | ) |
| Change due to Severance Expense, Net of Tax | | | - | | | | 0.01 | | | | - | | | | 0.05 | |
| Adjusted Net Income Per Common Share – Diluted | | $ | 0.22 | | | $ | 0.34 | | | $ | 1.06 | | | $ | 1.05 | |
(a) | Adjusted to reflect related tax benefit (expense) of ($2.3) million and $1.6 million for the three months ended December 31, 2013 and 2012, respectively and $8.0 million and ($5.6 million) for the years ended December 31, 2013 and 2012 respectively. |
| (b) | Reflects severance expense recognized in connection with the departures during 2012 of our former president and former chief operating officer. Adjusted to reflect related tax benefit of $0.1 million for the three months ended December 31, 2012, and $2.0 million for the year ended December 31, 2012. |
Proved Reserves Summary at December 31, 2013(1)
| Reserve Category | | Crude Oil (MBbls) | | | Natural Gas (MMcf) | | | 2013 MBoe(2) | | | 2012 MBoe(2) | | | % Change | | | 2013 Pre-Tax PV10% ($MM)(3) | |
| Proved Developed Producing | | | 26,150 | | | | 16,538 | | | | 28,906 | | | | 26,181 | | | | 10 | | | $ | 882 | |
| Proved Developed Non-Producing | | | 5,893 | | | | 4,105 | | | | 6,577 | | | | 4,056 | | | | 62 | | | | 151 | |
| Proved Undeveloped | | | 43,756 | | | | 29,525 | | | | 48,677 | | | | 37,356 | | | | 30 | | | | 488 | |
| Total Proved | | | 75,799 | | | | 50,168 | | | | 84,160 | | | | 67,593 | | | | 25 | | | $ | 1,521 | |
_________________
| (1) | The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2013 assuming constant realized prices of $88.00 per barrel of oil and $5.23 per Mcf of natural gas, which includes an uplift factor of 1.4 to reflect liquids and condensates (natural gas liquids are included with natural gas). Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, which averages are then adjusted to reflect applicable transportation and quality differentials. |
| (2) | Boe are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas. |
| (3) | Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. |
The table above assumes prices and costs discounted using an annual discount rate of 10% without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes.
The “Pre-tax PV10%” values of our proved reserves presented in the foregoing table may be considered a non-GAAP financial measure as defined by the SEC. The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves to the standardized measure of discounted future net cash flows.
SEC Pricing Proved Reserves (in thousands) | |
| Standardized Measure Reconciliation | |
| Pre-tax Present Value of estimated future net revenues (Pre-tax PV10%) | | $ | 1,521,289 | |
| Future income taxes, discounted at 10% | | | 296,923 | |
| Standardized measure of discounted future net cash flows | | $ | 1,224,367 | |
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer valuing the reserves. Further, our actual realized price for our oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.
