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| 8-K - NORTHERN OIL AND GAS, INC. FORM 8K, DATED AUGUST 5, 2015 - NORTHERN OIL & GAS, INC. | form8k_08052015.htm |
EXHIBIT 99.1
Northern Oil and Gas, Inc. Announces 2015 Second Quarter Results
WAYZATA, MINNESOTA — August 5, 2015 — Northern Oil and Gas, Inc. (NYSE MKT: NOG) today announced 2015 second quarter results.
2015 SECOND QUARTER HIGHLIGHTS
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·
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Production averaged 16,610 barrels of oil equivalent (“Boe”) per day, for a total of 1,511,554 Boe, an 8% increase over the second quarter of 2014
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·
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Oil and gas sales, including settled derivatives (hedges), totaled $94.0 million
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·
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Northern added 68 gross (6.9 net) wells to production during the second quarter
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·
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Approximately 2.9 million barrels of oil are hedged for the next four calendar quarters at an average price of approximately $90.00 per barrel
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·
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Enhanced liquidity position with $185 million of net proceeds from the May 2015 senior notes offering
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·
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$7.3 million weighted average AFE cost for wells consented to during the second quarter, down 21% from 2014
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Northern’s adjusted net income for the second quarter of 2015 was $11.5 million, or $0.19 per diluted share. Adjusted net income was negatively impacted by low natural gas, NGL and oil prices. GAAP net loss for the second quarter of 2015, which was impacted by a $282.0 million non-cash impairment charge, was $250.1 million, or a loss of $4.12 per diluted share. Adjusted EBITDA for the second quarter of 2015 was $70.4 million, an increase of 4% compared to the first quarter of 2015. See “Non-GAAP Financial Measures” below for additional information on these measures.
MANAGEMENT COMMENT
“Northern continues to be judicious with our capital expenditures by allocating spending to our highest rate of return opportunities,” commented Northern’s Chairman and Chief Executive Officer, Michael Reger. “Our financial position remains strong with a robust hedging position and liquidity of approximately $370 million. Northern’s capital budget is on track for approximately $140 million in 2015, down substantially from last year, while maintaining flat year-over-year production. Our capital allocation discipline, combined with the cost reductions operators are making in the field, should continue to drive returns higher.”
GUIDANCE AND LIQUIDITY UPDATE
Northern’s 2015 guidance remains unchanged, with 2015 total production expected to be essentially flat with 2014 based on Northern’s planned $140 million capital budget. Lower net well additions during the second half of 2015 will be partially offset by an increase in per well productivity.
During the second quarter, Northern issued $200 million in aggregate principle amount of 8.00% senior notes due 2020, resulting in net proceeds of $185 million that were used to repay borrowings under Northern’s revolving credit facility. As a result, at June 30, 2015, Northern had $188 million in outstanding borrowings under its revolving credit facility, which has a total borrowing base of $550 million. The remaining borrowing capacity under the revolving credit facility, together with an additional $7.1 million in cash, results in available liquidity of approximately $370 million at quarter-end.
CAPITAL EXPENDITURE UPDATE
During the second quarter of 2015, Northern incurred $30.3 million of capital expenditures on drilling and completion and capitalized workover costs. Capital expenditures trended higher in the first half of the year as wells in process reduced throughout the first half. In addition, during the second quarter Northern spent $2.1 million on acreage acquisitions and other acreage related activities in the Williston Basin, and incurred $0.9 million of other capitalized costs.
DRILLING AND COMPLETIONS UPDATE
Northern added 6.9 net wells to production during the second quarter, bringing its total producing well count to 199.2 net wells as of June 30, 2015. In the first half of 2015, Northern added a total of 13.5 net wells to production.
As of June 30, 2015, Northern was participating in 205 gross (10.8 net) wells that were drilling or awaiting completion, 94% of which are in Mountrail, McKenzie, Williams or Dunn County. Northern estimates that approximately 30% of these in-process wells will not be completed until late 2015 or early 2016.
As expected, the decline in Williston Basin activity has significantly reduced costs. During the second quarter of 2015, the weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in was $7.3 million, down 21% compared to the wells that Northern elected to participate in during 2014. In addition, with drilling activity concentrated in the core, Northern is seeing a significant increase in estimated ultimate recovery (or EUR) of the wells it is electing to participate in during 2015. From an internal rate of return perspective, this combination of lower costs and higher EURs is helping to offset the negative impact of lower commodity prices.
ACREAGE UPDATE
As of June 30, 2015, Northern controlled approximately 178,137 net acres targeting the Williston Basin Bakken and Three Forks. In the second quarter, Northern acquired leasehold interests covering an aggregate of approximately 1,306 net acres, for an average cost of $1,299 per net acre.
As of June 30, 2015, approximately 80% of Northern’s North Dakota acreage position, and approximately 67% of Northern’s total acreage position, was developed, held by production or held by operations.
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 open crude oil swap derivative contracts scheduled to settle after June 30, 2015.
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Contract Period
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Volume (Bbls)
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Weighted Average Price (per Bbl)
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||||||||
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2015:
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||||||||||
| Q3 | 990,000 | $ | 89.82 | |||||||
| Q4 | 990,000 | $ | 89.82 | |||||||
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2016:
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||||||||||
| Q1 | 450,000 | $ | 90.00 | |||||||
| Q2 | 450,000 | $ | 90.00 | |||||||
| Q3 | 450,000 | $ | 65.00 | |||||||
| Q4 | 450,000 | $ | 65.00 | |||||||
SECOND QUARTER 2015 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
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Three Months Ended
June 30,
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||||||||||||
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2015
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2014
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% Change
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||||||||||
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Net Production:
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||||||||||||
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Oil (Bbl)
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1,314,490 | 1,260,310 | 4 | |||||||||
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Natural Gas and NGLs (Mcf)
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1,182,386 | 844,279 | 40 | |||||||||
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Total (Boe)
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1,511,554 | 1,401,023 | 8 | |||||||||
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Average Daily Production:
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||||||||||||
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Oil (Bbl)
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14,445 | 13,850 | 4 | |||||||||
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Natural Gas and NGLs (Mcf)
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12,993 | 9,278 | 40 | |||||||||
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Total (Boe)
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16,610 | 15,396 | 8 | |||||||||
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Average Sales Prices:
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||||||||||||
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Oil (per Bbl)
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$ | 46.45 | $ | 90.75 | (49 | ) | ||||||
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Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)
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23.57 | (8.93 | ) | |||||||||
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Oil Net of Settled Derivatives (per Bbl)
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70.02 | 81.82 | (14 | ) | ||||||||
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Natural Gas and NGLs (per Mcf)
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1.69 | 8.04 | (79 | ) | ||||||||
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Realized Price on a Boe Basis Including all Realized Derivative Settlements
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62.22 | 78.45 | (21 | ) | ||||||||
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Operating Expenses (per Boe):
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||||||||||||
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Production Expenses
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$ | 8.97 | $ | 9.30 | (4 | ) | ||||||
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Production Taxes
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4.55 | 8.72 | (48 | ) | ||||||||
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General and Administrative Expense
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2.82 | 2.84 | (1 | ) | ||||||||
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Depletion, Depreciation, Amortization and Accretion
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24.31 | 30.13 | (19 | ) | ||||||||
Oil and Natural Gas Sales
In the second quarter of 2015, oil, natural gas and NGL sales, excluding the effect of settled derivatives, decreased 48% as compared to the second quarter of 2014, driven by a 52% decrease in realized prices, excluding the effect of settled derivatives, and partially offset by an 8% increase in production. The lower average realized price in the second quarter of 2015 as compared to the same period in 2014 was principally driven by lower average NYMEX oil and gas prices, which were partially offset by a lower oil price differential. Oil price differential during the second quarter of 2015 was $11.50 per barrel, as compared to $12.25 per barrel in the second quarter of 2014.
Derivative Instruments (Hedges)
Northern enters into derivative instruments (hedges) to manage the price risk attributable to future oil production. For the second quarter of 2015, Northern realized a gain on settled derivatives of $31.0 million, compared to an $11.3 million loss for the second quarter of 2014. Northern had a non-cash, mark-to-market derivative loss of $53.2 million in the second quarter of 2015, compared to a $35.3 million loss in the second quarter of 2014. As a result of the settled gain and the mark-to-market loss, there was a net loss of $22.2 million in the second quarter of 2015, compared to a net loss of $46.6 million in the second quarter of 2014. These net amounts are comprised of (i) cash gains and losses Northern recognized on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses Northern incurred on derivative instruments outstanding at period-end.
Production Expenses
Production expenses were $13.6 million in the second quarter of 2015 compared to $13.0 million in the second quarter of 2014. On a per unit basis, production expenses were $8.97 per Boe in the second quarter of 2015 compared to $9.30 per Boe in the second quarter of 2014.
Production Taxes
Northern pays production tax as a percentage of total oil and gas sales, before the effect of settled derivatives. These costs were $6.9 million in the second quarter of 2015 compared to $12.2 million in the second quarter of 2014. As a percentage of oil and natural gas sales, production taxes were 10.9% and 10.1% in the second quarter of 2015 and 2014, respectively. This increase in production tax rates as a percentage of oil and gas sales in the second quarter of 2015 is due to a declining portion of Northern’s production that qualifies for lower initial tax rates.
General and Administrative Expense
General and administrative expense was $4.3 million for the second quarter of 2015 compared to $4.0 million for the second quarter of 2014. On a per unit basis, second quarter 2015 general and administrative expenses were $2.82 per Boe compared with the $2.84 per Boe for the second quarter of 2014.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $36.7 million in the second quarter of 2015 compared to $42.2 million in the second quarter of 2014. Depletion expense, the largest component of DD&A, was $24.20 per Boe in the second quarter of 2015, compared to $30.02 per Boe in the second quarter of 2014. The aggregate decrease in depletion expense for the second quarter of 2015 compared to the second quarter of 2014 was driven by a 19% decrease in the depletion rate per Boe which was partially offset by an 8% increase in production.
Impairment of Oil and Natural Gas Properties
As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, Northern recorded a non-cash ceiling test impairment of $282.0 million for the three-month period ended June 30, 2015. Northern did not have any impairment of its proved oil and gas properties for the three-month period ended June 30, 2014. The impairment charge affected reported net income but did not reduce cash flow.
Interest Expense
Interest expense, net of capitalized interest, was $14.4 million in the second quarter of 2015 compared to $10.3 million in the second quarter of 2014. The increase in interest expense was primarily due to Northern’s capital development program and working capital requirements, which increased borrowings that were funded by the revolving credit facility and the issuance of $200 million in principal amount of senior notes.
Income Tax Provision
The income tax benefit recognized during the second quarter of 2015 was $66.9 million or 21.1% of the loss before income taxes, as compared to an income tax benefit of $2.8 million or 38.4% in the second quarter of 2014. The lower effective tax rate in 2015 relates to the valuation allowance placed on the net deferred tax asset in the second quarter of 2015, in addition to state income taxes and estimated permanent differences.
Net Income
Northern recorded a net loss of $250.1 million, or approximately $4.12 per diluted share, for the second quarter of 2015, compared to a net loss of $4.4 million, or approximately $0.07 per diluted share, for the second quarter of 2014. Net loss in the second quarter of 2015 was impacted by the non-cash impairment of oil and natural gas properties, the valuation allowance placed on the net deferred tax asset, and a non-cash loss on the mark-to-market of derivative instruments.
Non-GAAP Financial Measures
Adjusted Net Income for the second quarter of 2015 was $11.5 million (representing approximately $0.19 per diluted share), compared to $17.3 million (representing approximately $0.29 per diluted share) for the second quarter of 2014. The decrease in non-GAAP Adjusted Net Income is primarily due to lower realized commodity prices as well as higher interest expense, which were partially offset by lower depletion expense. 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) impairment of oil and natural gas properties, net of tax.
Adjusted EBITDA for the second quarter of 2015 was $70.4 million, compared to Adjusted EBITDA of $81.4 million for the second quarter of 2014. The decrease in Adjusted EBITDA is primarily due to lower realized commodity prices, which were partially offset by the continued addition of crude oil and natural gas production from wells in 2015 compared to 2014. 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, (v) non-cash share based compensation expense and (vi) impairment of oil and natural gas properties.
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. A reconciliation of these measures to the most directly comparable GAAP measure is included in the accompanying financial tables found later in this release. Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically, management believes the non-GAAP results included herein provide useful information to both management and investors by excluding certain expenses and unrealized derivatives gains and losses that management believes are not indicative of Northern’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring Northern’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.
SECOND QUARTER 2015 EARNINGS RELEASE CONFERENCE CALL AND WEBCAST
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 Thursday, August 6, 2015 at 10:00 a.m. Central Time. Details for the conference call are as follows:
Dial-In Number: (855) 638-5677 (US/Canada) and (262) 912-4762 (International)
Conference ID: 94735042 - Northern Oil and Gas, Inc. Second Quarter 2015 Earnings Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code: 94735042 - Replay will be available through August 13, 2015
Webcast: www.NorthernOil.com
UPCOMING CONFERENCE SCHEDULE
EnerCom’s The Oil & Gas Conference 20
August 16-20, 2015, Denver, CO
ABOUT NORTHERN OIL AND GAS
Northern Oil and Gas, Inc. is an exploration and production company with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana.
More information about Northern Oil and Gas, Inc. can be found at www.NorthernOil.com.
SAFE HARBOR
This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “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, changes in Northern’s reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which Northern conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern’s ability to raise capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern’s operations, products, services and prices.
Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control.
CONTACT:
Brandon Elliott
EVP, Corporate Development and Strategy
952-476-9800
belliott@northernoil.com
Erik Nerhus
VP, Business Development
952-476-9800
enerhus@northernoil.com
SOURCE Northern Oil and Gas, Inc.
NORTHERN OIL AND GAS, INC.
STATEMENTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2015 AND 2014
(UNAUDITED)
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Three Months Ended
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Six Months Ended
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June 30,
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June 30,
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2015
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2014
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2015
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2014
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REVENUES
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Oil and Gas Sales
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$ | 63,064,333 | $ | 121,155,047 | $ | 113,518,481 | $ | 217,958,016 | ||||||||
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Gain (Loss) on Derivative Instruments, Net
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(22,211,048 | ) | (46,556,303 | ) | 3,452,235 | (61,233,966 | ) | |||||||||
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Other Revenue
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9,909 | 3,269 | 17,117 | 3,269 | ||||||||||||
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Total Revenues
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40,863,194 | 74,602,013 | 116,987,833 | 156,727,319 | ||||||||||||
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OPERATING EXPENSES
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||||||||||||||||
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Production Expenses
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13,564,801 | 13,033,322 | 27,763,891 | 24,710,750 | ||||||||||||
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Production Taxes
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6,871,788 | 12,213,387 | 12,284,896 | 22,004,588 | ||||||||||||
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General and Administrative Expense
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4,256,436 | 3,980,819 | 8,609,242 | 7,978,509 | ||||||||||||
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Depletion, Depreciation, Amortization and Accretion
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36,745,805 | 42,212,250 | 81,958,844 | 78,313,171 | ||||||||||||
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Impairment of Oil and Natural Gas Properties
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281,964,097 | - | 642,393,059 | - | ||||||||||||
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Total Expenses
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343,402,927 | 71,439,778 | 773,009,932 | 133,007,018 | ||||||||||||
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(LOSS) INCOME FROM OPERATIONS
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(302,539,733 | ) | 3,162,235 | (656,022,099 | ) | 23,720,301 | ||||||||||
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OTHER INCOME (EXPENSE)
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||||||||||||||||
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Interest Expense, Net of Capitalization
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(14,387,693 | ) | (10,326,789 | ) | (26,124,240 | ) | (20,225,758 | ) | ||||||||
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Other Income (Expense)
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199 | 2,104 | 542 | 32,771 | ||||||||||||
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Total Other Income (Expense)
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(14,387,494 | ) | (10,324,685 | ) | (26,123,698 | ) | (20,192,987 | ) | ||||||||
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(LOSS) INCOME BEFORE INCOME TAXES
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(316,927,227 | ) | (7,162,450 | ) | (682,145,797 | ) | 3,527,314 | |||||||||
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INCOME TAX PROVISION (BENEFIT)
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(66,866,610 | ) | (2,750,000 | ) | (202,346,610 | ) | 1,350,000 | |||||||||
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NET (LOSS) INCOME
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$ | (250,060,617 | ) | $ | (4,412,450 | ) | $ | (479,799,187 | ) | $ | 2,177,314 | |||||
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Net (Loss) Income Per Common Share – Basic
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$ | (4.12 | ) | $ | (0.07 | ) | $ | (7.92 | ) | $ | 0.04 | |||||
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Net (Loss) Income Per Common Share – Diluted
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$ | (4.12 | ) | $ | (0.07 | ) | $ | (7.92 | ) | $ | 0.04 | |||||
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Weighted Average Shares Outstanding – Basic
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60,644,635 | 60,504,781 | 60,600,652 | 60,852,322 | ||||||||||||
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Weighted Average Shares Outstanding – Diluted
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60,644,635 | 60,504,781 | 60,600,652 | 61,059,485 | ||||||||||||
NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
JUNE 30, 2015 AND DECEMBER 31, 2014
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June 30, 2015
(unaudited)
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December 31, 2014
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CURRENT ASSETS
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||||||||
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Cash and Cash Equivalents
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$ | 7,112,054 | $ | 9,337,512 | ||||
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Trade Receivables
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82,406,315 | 85,931,719 | ||||||
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Advances to Operators
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992,739 | 930,034 | ||||||
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Prepaid and Other Expenses
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1,540,885 | 895,088 | ||||||
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Derivative Instruments
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83,581,535 | 128,893,220 | ||||||
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Total Current Assets
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175,633,528 | 225,987,573 | ||||||
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PROPERTY AND EQUIPMENT
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||||||||
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Oil and Natural Gas Properties, Full Cost Method of Accounting
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||||||||
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Proved
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2,276,966,123 | 2,167,452,297 | ||||||
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Unproved
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19,040,028 | 50,642,433 | ||||||
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Other Property and Equipment
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1,885,932 | 1,870,369 | ||||||
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Total Property and Equipment
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2,297,892,083 | 2,219,965,099 | ||||||
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Less – Accumulated Depreciation, Depletion and Impairment
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(1,182,200,074 | ) | (458,038,546 | ) | ||||
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Total Property and Equipment, Net
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1,115,692,009 | 1,761,926,553 | ||||||
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DERIVATIVE INSTRUMENTS
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2,286,763 | 25,013,011 | ||||||
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DEFERRED TAX ASSET
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27,423,683 | - | ||||||
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DEBT ISSUANCE COSTS, NET
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17,730,903 | 13,819,195 | ||||||
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TOTAL ASSETS
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$ | 1,338,766,886 | $ | 2,026,746,332 | ||||
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LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||||
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CURRENT LIABILITIES
|
||||||||
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Accounts Payable
|
$ | 115,820,230 | $ | 231,557,547 | ||||
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Accrued Expenses
|
5,221,374 | 6,653,124 | ||||||
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Accrued Interest
|
5,352,777 | 3,585,536 | ||||||
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Derivative Instruments
|
65,732 | - | ||||||
|
Deferred Tax Liability
|
27,423,683 | 43,938,000 | ||||||
|
Asset Retirement Obligations
|
209,750 | - | ||||||
|
Total Current Liabilities
|
154,093,546 | 285,734,207 | ||||||
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LONG-TERM LIABILITIES
|
||||||||
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Revolving Credit Facility
|
188,000,000 | 298,000,000 | ||||||
|
8% Senior Notes
|
697,548,735 | 508,053,097 | ||||||
|
Derivative Instruments
|
- | 579,070 | ||||||
|
Asset Retirement Obligations
|
5,332,909 | 5,105,762 | ||||||
|
Deferred Tax Liability
|
- | 158,412,555 | ||||||
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Total Long-Term Liabilities
|
890,881,644 | 970,150,484 | ||||||
|
TOTAL LIABILITIES
|
1,044,975,190 | 1,255,884,691 | ||||||
|
COMMITMENTS AND CONTINGENCIES (NOTE 8)
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||||||||
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STOCKHOLDERS’ EQUITY
|
||||||||
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Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding
|
- | - | ||||||
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Common Stock, Par Value $.001; 95,000,000 Authorized, (6/30/2015 – 61,603,071
Shares Outstanding and 12/31/2014 – 61,066,712 Shares Outstanding)
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61,603 | 61,067 | ||||||
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Additional Paid-In Capital
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436,060,992 | 433,332,285 | ||||||
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Retained Earnings (Deficit)
|
(142,330,899 | ) | 337,468,289 | |||||
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Total Stockholders’ Equity
|
293,791,696 | 770,861,641 | ||||||
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TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$ | 1,338,766,886 | $ | 2,026,746,332 | ||||
Reconciliation of Adjusted Net Income
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||
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Net (Loss) Income
|
$ | (250,060,617 | ) | $ | (4,412,450 | ) | $ | (479,799,187 | ) | $ | 2,177,314 | |||||
|
Add:
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||||||||||||||||
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Impact of Selected Items:
|
||||||||||||||||
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Loss on the Mark-to-Market of Derivative Instruments
|
53,193,228 | 35,307,533 | 67,524,595 | 43,167,216 | ||||||||||||
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Impairment of Oil and Natural Gas Properties
|
281,964,097 | - | 642,393,059 | - | ||||||||||||
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Selected Items, Before Income Taxes
|
335,157,325 | 35,307,533 | 709,917,654 | 43,167,216 | ||||||||||||
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Income Tax of Selected Items(1)
|
(73,583,617 | ) | (13,558,093 | ) | (212,616,501 | ) | (16,576,211 | ) | ||||||||
|
Selected Items, Net of Income Taxes
|
261,573,708 | 21,749,440 | 497,301,153 | 26,591,005 | ||||||||||||
|
Adjusted Net Income
|
$ | 11,513,091 | $ | 17,336,990 | $ | 17,501,966 | $ | 28,768,319 | ||||||||
|
Weighted Average Shares Outstanding – Basic
|
60,644,635 | 60,504,781 | 60,600,652 | 60,852,322 | ||||||||||||
|
Weighted Average Shares Outstanding – Diluted
|
60,790,352 | 60,676,947 | 60,712,210 | 61,059,485 | ||||||||||||
|
Net (Loss) Income Per Common Share – Basic
|
$ | (4.12 | ) | $ | (0.07 | ) | $ | (7.92 | ) | $ | 0.04 | |||||
|
Add:
|
||||||||||||||||
|
Impact of Selected Items, Net of Income Taxes
|
4.31 | 0.36 | 8.21 | 0.43 | ||||||||||||
|
Adjusted Net Income Per Common Share – Basic
|
$ | 0.19 | $ | 0.29 | $ | 0.29 | $ | 0.47 | ||||||||
|
Net (Loss) Income Per Common Share – Diluted
|
$ | (4.11 | ) | $ | (0.07 | ) | $ | (7.90 | ) | $ | 0.04 | |||||
|
Add:
|
||||||||||||||||
|
Impact of Selected Items, Net of Income Taxes
|
4.30 | 0.36 | 8.19 | 0.43 | ||||||||||||
|
Adjusted Net Income Per Common Share – Diluted
|
$ | 0.19 | $ | 0.29 | $ | 0.29 | $ | 0.47 | ||||||||
_____________________
|
(1)
|
For the 2015 columns, this represents tax impact using an estimated tax rate of 36.9% and 37.0% for the three and six months ended June 30, 2015, respectively. These columns include a $49.9 million adjustment for the establishment of a valuation allowance in the second quarter of 2015. For the 2014 columns, this represents tax impact using an estimated tax rate of 38.4%.
|
Reconciliation of Adjusted EBITDA
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||
|
Net (Loss) Income
|
$ | (250,060,617 | ) | $ | (4,412,450 | ) | $ | (479,799,187 | ) | $ | 2,177,314 | |||||
|
Add:
|
||||||||||||||||
|
Interest Expense
|
14,387,693 | 10,326,789 | 26,124,240 | 20,225,758 | ||||||||||||
|
Income Tax Provision (Benefit)
|
(66,866,610 | ) | (2,750,000 | ) | (202,346,610 | ) | 1,350,000 | |||||||||
|
Depreciation, Depletion, Amortization, and Accretion
|
36,745,805 | 42,212,250 | 81,958,844 | 78,313,171 | ||||||||||||
|
Impairment of Oil and Natural Gas Properties
|
281,964,097 | - | 642,393,059 | - | ||||||||||||
|
Non-Cash Share Based Compensation
|
1,050,157 | 727,344 | 2,080,474 | 1,285,209 | ||||||||||||
|
Loss on the Mark-to-Market of Derivative Instruments
|
53,193,228 | 35,307,533 | 67,524,595 | 43,167,216 | ||||||||||||
|
Adjusted EBITDA
|
$ | 70,413,753 | $ | 81,411,466 | $ | 137,935,415 | $ | 146,518,668 | ||||||||