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| 8-K - NORTHERN OIL AND GAS, INC. FORM 8K, DATED NOVEMBER 4, 2015 - NORTHERN OIL & GAS, INC. | form8k_11042015.htm |
Exhibit 99.1
Northern Oil and Gas, Inc. Announces 2015 Third Quarter Results
WAYZATA, MINNESOTA — November 4, 2015 — Northern Oil and Gas, Inc. (NYSE MKT: NOG) today announced 2015 third quarter results.
2015 THIRD QUARTER HIGHLIGHTS
· Production averaged 15,844 barrels of oil equivalent (“Boe”) per day, for a total of 1,457,610 Boe
· Oil and gas sales, including settled derivatives (hedges), totaled $92.7 million
· Northern’s credit facility balance was paid down by $18 million during the quarter, to $170 million, as a result of positive cash flow from operations
· Northern added 85 gross (2.7 net) wells to production during the third quarter
·Approximately 2.3 million barrels of oil are hedged for the next four calendar quarters at an average price of approximately $85.00 per barrel
Northern’s adjusted net income for the third quarter of 2015 was $14.6 million, or $0.24 per diluted share. GAAP net loss for the third quarter of 2015, which was impacted by a $354.4 million non-cash impairment charge, was $323.2 million, or a loss of $5.33 per diluted share. Adjusted EBITDA for the third quarter of 2015 was $71.7 million. See “Non-GAAP Financial Measures” below for additional information on these measures.
MANAGEMENT COMMENT
“As we continue to focus our investments on our highest rate of return opportunities, we are seeing the added benefit of lower costs and innovative completion designs driving productivity,” commented Northern’s Chairman and Chief Executive Officer, Michael Reger. “In addition, the net effect of our capital spending discipline, hedge book and high-grade well additions allowed us to maintain our borrowing base at $550 million, generate free cash flow and reduce debt during the quarter.”
LIQUIDITY
At September 30, 2015, Northern had $170 million in outstanding borrowings under its revolving credit facility, which has a total borrowing base that was recently reaffirmed at $550 million. The remaining borrowing capacity under the revolving credit facility, together with an additional $7.0 million in cash, results in available liquidity of approximately $387 million at quarter-end, which is an increase of $18 million versus the prior quarter.
HEDGING
Northern hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following table summarizes Northern’s open crude oil swap derivative contracts scheduled to settle after September 30, 2015.
|
Contract Period
|
Volume (Bbls)
|
Weighted Average Price (per Bbl)
|
||||||||
|
2015:
|
||||||||||
| Q4 | 990,000 | $ | 89.82 | |||||||
|
2016:
|
||||||||||
| Q1 | 450,000 | $ | 90.00 | |||||||
| Q2 | 450,000 | $ | 90.00 | |||||||
| Q3 | 450,000 | $ | 65.00 | |||||||
| Q4 | 450,000 | $ | 65.00 | |||||||
CAPITAL EXPENDITURES & DRILLING ACTIVITY
|
Third Quarter
2015
|
First Nine Months 2015
|
|||||||
|
Capital Expenditures Incurred:
|
||||||||
|
Drilling, Completion & Capitalized Workover Expense
|
$25.7 million
|
$97.3 million
|
||||||
|
Acreage
|
$0.9 million
|
$5.0 million
|
||||||
|
Other
|
$0.9 million
|
$3.1 million
|
||||||
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Net Wells Added to Production
|
2.7 | 16.2 | ||||||
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Net Producing Wells (Period-End)
|
201.9 | 201.9 | ||||||
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Net Wells in Process (Period-End)
|
10.1 |
NA
|
||||||
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Weighted Average AFE for In-Process Wells (Period End)
|
$7.9 million
|
NA
|
||||||
Capital expenditures have continued to trend lower in the second half of the year. Northern estimates that approximately 60% to 70% of its in-process wells will not be completed until 2016. During the first nine months of 2015, the weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in (consented) was $7.7 million. Although Northern’s original capital expenditure budget remains unchanged at $140 million, current Williston Basin activity levels could result in Northern finishing 2015 slightly under this spending level.
THIRD QUARTER 2015 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
|
Three Months Ended
September 30,
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||||||||||||
|
2015
|
2014
|
% Change
|
||||||||||
|
Net Production:
|
||||||||||||
|
Oil (Bbl)
|
1,261,823 | 1,348,146 | (6 | ) | ||||||||
|
Natural Gas and NGLs (Mcf)
|
1,174,721 | 990,351 | 19 | |||||||||
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Total (Boe)
|
1,457,610 | 1,513,205 | (4 | ) | ||||||||
|
Average Daily Production:
|
||||||||||||
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Oil (Bbl)
|
13,715 | 14,654 | (6 | ) | ||||||||
|
Natural Gas and NGL (Mcf)
|
12,769 | 10,765 | 19 | |||||||||
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Total (Boe)
|
15,844 | 16,448 | (4 | ) | ||||||||
|
Average Sales Prices:
|
||||||||||||
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Oil (per Bbl)
|
$ | 38.26 | $ | 84.32 | (55 | ) | ||||||
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Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)
|
34.04 | (5.20 | ) | |||||||||
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Oil Net of Settled Derivatives (per Bbl)
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72.30 | 79.12 | (9 | ) | ||||||||
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Natural Gas and NGLs (per Mcf)
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1.28 | 5.56 | (77 | ) | ||||||||
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Realized Price on a Boe Basis Including all Realized Derivative Settlements
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63.62 | 74.13 | (14 | ) | ||||||||
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Costs and Expenses (per Boe):
|
||||||||||||
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Production Expenses
|
$ | 8.62 | $ | 9.73 | (11 | ) | ||||||
|
Production Taxes
|
3.46 | 7.98 | (57 | ) | ||||||||
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General and Administrative Expense
|
3.17 | 3.11 | 2 | |||||||||
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Depletion, Depreciation, Amortization and Accretion
|
21.72 | 30.17 | (28 | ) | ||||||||
|
Impairment of Oil and Natural Gas Properties
|
243.15 | - | - | |||||||||
|
Net Producing Wells at Period End
|
201.9 | 177.5 | 14 | |||||||||
Oil and Natural Gas Sales
In the third quarter of 2015, oil, natural gas and NGL sales, excluding the effect of settled derivatives, decreased 58% as compared to the third quarter of 2014, driven by a 57% decrease in realized prices, excluding the effect of settled derivatives, and a 4% decrease in production. The lower average realized price in the third 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 third quarter of 2015 was $8.24 per barrel, as compared to $12.93 per barrel in the third quarter of 2014. Northern expects fourth quarter oil price differential to average $8.00 - $10.00 per barrel.
Derivative Instruments (Hedges)
Northern enters into derivative instruments to manage the price risk attributable to future oil production. Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses recognized on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses incurred on derivative instruments outstanding at period-end.
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Three Months Ended
September 30,
|
||||||||
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2015
|
2014
|
|||||||
|
(in millions)
|
||||||||
|
Derivative Instruments (Hedges):
|
||||||||
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Cash Derivative Settlements
|
$ | 43.0 | $ | (7.0 | ) | |||
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Non-Cash Mark-to-Market of Derivative Instruments
|
8.4 | 68.6 | ||||||
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Gain (Loss) on Derivative Instruments, Net
|
$ | 51.4 | $ | 61.6 | ||||
Northern’s average realized price (including all cash derivative settlements) received during the third quarter of 2015 was $63.62 per Boe compared to $74.13 per Boe in the third quarter of 2014. The gain (loss) on settled derivatives increased Northern’s average realized price per Boe by $29.47 in the third quarter of 2015 and decreased average realized price per Boe by $4.64 in the third quarter of 2014.
As a result of forward oil price changes, Northern recognized a non-cash mark-to-market derivative gain of $8.4 million in the third quarter of 2015 compared to a $68.6 million gain in the third quarter of 2014. At September 30, 2015, all derivative contracts were recorded at their fair value, which was a net asset of $94.2 million, an increase of $86.7 million from the $7.5 million net asset recorded as of September 30, 2014.
Production Expenses
Production expenses decreased from $14.7 million in the third quarter of 2014 to $12.6 million in the third quarter of 2015. On a per unit basis, production expenses decreased 11% or $1.11 per Boe to $8.62 per Boe in the third quarter of 2015 compared to the third quarter of 2014. The lower cost on a per unit basis in 2015 is primarily due to reduced contract labor and maintenance costs. Northern now expects fourth quarter production expenses to average between $8.75 and $9.00 per Boe.
Production Taxes
Northern pays production taxes based on realized crude oil and natural gas sales. These costs were $5.0 million in the third quarter of 2015 compared to $12.1 million in the third quarter of 2014. The $7.1 million decrease in production taxes in 2015 compared to 2014 was due to the decline in oil, natural gas and NGL sales, excluding the effect of settled derivatives. As a percentage of oil and natural gas sales, production taxes were flat at 10.1% in the third quarter of both 2015 and 2014. Northern now expects fourth quarter 2015 production taxes as a percentage of oil and natural gas sales to average 10.5%.
General and Administrative Expense
General and administrative expense was $4.6 million for the third quarter of 2015 compared to $4.7 million for the third quarter of 2014. In the third quarter of 2015, Northern restructured certain of its operations in response to the current commodity price environment, which included a reduction in workforce. Northern incurred $0.5 million in restructuring costs in the third quarter of 2015 as a result of these actions. Northern expects fourth quarter 2015 general and administrative expenses to average $3.00 per Boe.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $31.7 million in the third quarter of 2015 compared to $45.6 million in the third quarter of 2014. Depletion expense, the largest component of DD&A, was $21.61 per Boe in the third quarter of 2015 compared to $30.02 per Boe in the third quarter of 2014. The aggregate decrease in depletion expense for the third quarter of 2015 compared to the third quarter of 2014 was driven by a 28% decrease in the depletion rate per Boe as well as a 4% production decrease in 2015 as compared to 2014.
Impairment of Oil and Natural Gas Properties
As a result of current low commodity prices and their effect on the proved reserve values of properties in 2015, Northern recorded a non-cash ceiling test impairment of $354.4 million in the third quarter of 2015. Northern did not have any impairment of its proved oil and gas properties in the third quarter of 2014. The impairment charge affected reported net income but did not reduce cash flow.
Interest Expense
Interest expense, net of capitalized interest, was $16.2 million in the third quarter of 2015 compared to $10.6 million in the third quarter of 2014. The increase in interest expense was primarily due to Northern’s capital development program and the issuance of $200 million in principal amount of 2015 Mirror Notes, offset by a decrease in the amount drawn on the revolving credit facility.
Income Tax Provision
The income tax benefit recognized during the third quarter of 2015 was $0.1 million or 0.0% of the loss before income taxes, as compared to an income tax provision of $35.1 million or 37.7% of income before income taxes in the third quarter of 2014. The lower effective tax rate in 2015 relates to the valuation allowance placed on the net deferred tax asset in the third quarter of 2015, in addition to state income taxes and estimated permanent differences.
Net Income
Northern recorded a net loss of $323.2 million, or approximately $5.33 per diluted share, for the third quarter of 2015, compared to a net gain of $58.0 million, or approximately $0.95 per diluted share, for the third quarter of 2014. Net loss in the third 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 third quarter of 2015 was $14.6 million (representing approximately $0.24 per diluted share), compared to $15.6 million (representing approximately $0.26 per diluted share) for the third quarter of 2014. For the third quarter of 2015, 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, (ii) restructuring costs, net of tax, (iii) impairment of oil and natural gas properties, net of tax and (iv) certain legal settlements, net of tax.
Adjusted EBITDA for the third quarter of 2015 was $71.7 million, compared to Adjusted EBITDA of $81.4 million for the third quarter of 2014. The decrease in Adjusted EBITDA is primarily due to lower realized commodity prices 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.
ACREAGE
As of September 30, 2015, Northern controlled approximately 169,020 net acres targeting the Williston Basin Bakken and Three Forks. In the third quarter, Northern acquired leasehold interests covering an aggregate of approximately 952 net acres, for an average cost of $462 per net acre. As of September 30, 2015, approximately 80% of Northern’s North Dakota acreage position, and approximately 71% of Northern’s total acreage position, was developed, held by production or held by operations.
GUIDANCE
Northern continues to expect 2015 total production to be flat compared to 2014 production levels, with full year capital expenditures expected to come in at or slightly below the planned $140 million capital budget. Lower net well additions in the second half of 2015 are expected to be partially offset by an increase in per well productivity. Management’s current expectations for certain fourth quarter operating metrics are as follows:
|
4th Quarter 2015
|
||||
|
Operating Expenses:
|
||||
|
Production Expenses (per Boe)
|
$ | 8.75 - $9.00 | ||
|
Production Taxes (% of Oil & Gas Sales)
|
10.5 | % | ||
|
General and Admin. Expense (per Boe)
|
$ | 3.00 | ||
|
Average Differential to NYMEX WTI
|
($10.00) to ($8.00)
|
|||
THIRD QUARTER 2015 EARNINGS RELEASE CONFERENCE CALL
In conjunction with Northern’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Thursday, November 5, 2015 at 10:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via the company’s website, www.northernoil.com, or by phone as follows:
Dial-In Number: (855) 638-5677 (US/Canada) and (262) 912-4762 (International)
Conference ID: 69717407 - Northern Oil and Gas, Inc. Third Quarter 2015 Earnings Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code: 69717407 - Replay will be available through November 12, 2015
UPCOMING CONFERENCE SCHEDULE
Jefferies Energy Conference
November 10 – 12, 2015, Houston TX
Capital One Securities 10th Annual Energy Conference
December 8 – 10, 2015 New Orleans, LA
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
SOURCE Northern Oil and Gas, Inc.
CONDENSED STATEMENTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014
(UNAUDITED)
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
|
September 30,
|
September 30,
|
|||||||||||||||
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||
|
REVENUES
|
||||||||||||||||
|
Oil and Gas Sales
|
$ | 49,779,903 | $ | 119,191,594 | $ | 163,298,384 | $ | 337,149,610 | ||||||||
|
Gain on Derivative Instruments, Net
|
51,366,762 | 61,583,301 | 54,818,997 | 349,335 | ||||||||||||
|
Other Revenue
|
9,887 | 2,594 | 27,004 | 5,863 | ||||||||||||
|
Total Revenues
|
101,156,552 | 180,777,489 | 218,144,385 | 337,504,808 | ||||||||||||
|
OPERATING EXPENSES
|
||||||||||||||||
|
Production Expenses
|
12,567,423 | 14,717,257 | 40,331,314 | 39,428,008 | ||||||||||||
|
Production Taxes
|
5,048,227 | 12,068,494 | 17,333,123 | 34,073,083 | ||||||||||||
|
General and Administrative Expense
|
4,614,771 | 4,698,972 | 13,224,012 | 12,677,481 | ||||||||||||
|
Depletion, Depreciation, Amortization and Accretion
|
31,670,479 | 45,646,232 | 113,629,323 | 123,959,402 | ||||||||||||
|
Impairment of Oil and Natural Gas Properties
|
354,422,654 | - | 996,815,713 | - | ||||||||||||
|
Total Expenses
|
408,323,554 | 77,130,955 | 1,181,333,485 | 210,137,974 | ||||||||||||
|
INCOME (LOSS) FROM OPERATIONS
|
(307,167,002 | ) | 103,646,534 | (963,189,100 | ) | 127,366,834 | ||||||||||
|
OTHER INCOME (EXPENSE)
|
||||||||||||||||
|
Interest Expense, Net of Capitalization
|
(16,154,160 | ) | (10,624,246 | ) | (42,278,400 | ) | (30,850,004 | ) | ||||||||
|
Other Income (Expense)
|
1,586 | 13,022 | 2,128 | 45,794 | ||||||||||||
|
Total Other Income (Expense)
|
(16,152,574 | ) | (10,611,224 | ) | (42,276,272 | ) | (30,804,210 | ) | ||||||||
|
INCOME (LOSS) BEFORE INCOME TAXES
|
(323,319,576 | ) | 93,035,310 | (1,005,465,372 | ) | 96,562,624 | ||||||||||
|
INCOME TAX PROVISION (BENEFIT)
|
(77,544 | ) | 35,050,000 | (202,424,154 | ) | 36,400,000 | ||||||||||
|
NET INCOME (LOSS)
|
$ | (323,242,032 | ) | $ | 57,985,310 | $ | (803,041,218 | ) | $ | 60,162,624 | ||||||
|
Net Income (Loss) Per Common Share – Basic
|
$ | (5.33 | ) | $ | 0.96 | $ | (13.25 | ) | $ | 0.99 | ||||||
|
Net Income (Loss) Per Common Share – Diluted
|
$ | (5.33 | ) | $ | 0.95 | $ | (13.25 | ) | $ | 0.99 | ||||||
|
Weighted Average Shares Outstanding – Basic
|
60,679,257 | 60,559,827 | 60,627,142 | 60,753,752 | ||||||||||||
|
Weighted Average Shares Outstanding – Diluted
|
60,679,257 | 60,736,502 | 60,627,142 | 60,950,641 | ||||||||||||
NORTHERN OIL AND GAS, INC.
CONDENSED BALANCE SHEETS
SEPTEMBER 30, 2015 AND DECEMBER 31, 2014
|
September 30, 2015
(unaudited)
|
December 31, 2014
|
|||||||
|
CURRENT ASSETS
|
||||||||
|
Cash and Cash Equivalents
|
$ | 7,042,258 | $ | 9,337,512 | ||||
|
Trade Receivables
|
91,293,591 | 85,931,719 | ||||||
|
Advances to Operators
|
2,002,713 | 930,034 | ||||||
|
Prepaid and Other Expenses
|
983,612 | 895,088 | ||||||
|
Derivative Instruments
|
87,881,527 | 128,893,220 | ||||||
|
Total Current Assets
|
189,203,701 | 225,987,573 | ||||||
|
PROPERTY AND EQUIPMENT
|
||||||||
|
Oil and Natural Gas Properties, Full Cost Method of Accounting
|
||||||||
|
Proved
|
2,308,144,736 | 2,167,452,297 | ||||||
|
Unproved
|
15,341,573 | 50,642,433 | ||||||
|
Other Property and Equipment
|
1,891,228 | 1,870,369 | ||||||
|
Total Property and Equipment
|
2,325,377,537 | 2,219,965,099 | ||||||
|
Less – Accumulated Depreciation, Depletion and Impairment
|
(1,568,202,406 | ) | (458,038,546 | ) | ||||
|
Total Property and Equipment, Net
|
757,175,131 | 1,761,926,553 | ||||||
|
DERIVATIVE INSTRUMENTS
|
6,330,398 | 25,013,011 | ||||||
|
DEFERRED TAX ASSET
|
31,695,562 | - | ||||||
|
DEBT ISSUANCE COSTS, NET
|
16,831,376 | 13,819,195 | ||||||
|
TOTAL ASSETS
|
$ | 1,001,236,168 | $ | 2,026,746,332 | ||||
|
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
|
||||||||
|
CURRENT LIABILITIES
|
||||||||
|
Accounts Payable
|
$ | 98,885,559 | $ | 231,557,547 | ||||
|
Accrued Expenses
|
6,266,474 | 6,653,124 | ||||||
|
Accrued Interest
|
19,358,330 | 3,585,536 | ||||||
|
Derivative Instruments
|
678 | - | ||||||
|
Deferred Tax Liability
|
31,695,562 | 43,938,000 | ||||||
|
Asset Retirement Obligations
|
212,269 | - | ||||||
|
Total Current Liabilities
|
156,418,872 | 285,734,207 | ||||||
|
LONG-TERM LIABILITIES
|
||||||||
|
Revolving Credit Facility
|
170,000,000 | 298,000,000 | ||||||
|
8% Senior Notes
|
697,676,782 | 508,053,097 | ||||||
|
Derivative Instruments
|
- | 579,070 | ||||||
|
Asset Retirement Obligations
|
5,482,237 | 5,105,762 | ||||||
|
Deferred Tax Liability
|
- | 158,412,555 | ||||||
|
Total Long-Term Liabilities
|
873,159,019 | 970,150,484 | ||||||
|
TOTAL LIABILITIES
|
1,029,577,891 | 1,255,884,691 | ||||||
|
COMMITMENTS AND CONTINGENCIES (NOTE 8)
|
||||||||
|
STOCKHOLDERS’ EQUITY (DEFICIT)
|
||||||||
|
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding
|
- | - | ||||||
|
Common Stock, Par Value $.001; 95,000,000 Authorized, (9/30/2015 – 61,600,803
Shares Outstanding and 12/31/2014 – 61,066,712 Shares Outstanding)
|
61,601 | 61,067 | ||||||
|
Additional Paid-In Capital
|
437,169,607 | 433,332,285 | ||||||
|
Retained Earnings (Deficit)
|
(465,572,931 | ) | 337,468,289 | |||||
|
Total Stockholders’ Equity (Deficit)
|
(28,341,723 | ) | 770,861,641 | |||||
|
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
|
$ | 1,001,236,168 | $ | 2,026,746,332 | ||||
Reconciliation of Adjusted Net Income
|
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||
|
Net (Loss) Income
|
$ | (323,242,032 | ) | $ | 57,985,310 | $ | (803,041,218 | ) | $ | 60,162,624 | ||||||
|
Add:
|
||||||||||||||||
|
Impact of Selected Items:
|
||||||||||||||||
|
(Gain) Loss on the Mark-to-Market of Derivative Instruments
|
(8,408,682 | ) | (68,600,900 | ) | 59,115,913 | (25,433,684 | ) | |||||||||
|
Restructuring Costs
|
523,487 | - | 523,487 | - | ||||||||||||
|
Impairment of Oil and Natural Gas Properties
|
354,422,654 | - | 996,815,713 | - | ||||||||||||
|
Legal Settlements
|
- | 577,000 | - | 577,000 | ||||||||||||
|
Selected Items, Before Income Taxes (Benefit)
|
346,537,459 | (68,023,900 | ) | 1,056,455,113 | (24,856,684 | ) | ||||||||||
|
Income Tax of Selected Items(1)
|
(8,710,160 | ) | 25,645,010 | (221,312,923 | ) | 9,370,970 | ||||||||||
|
Selected Items, Net of Income Taxes (Benefit)
|
337,827,299 | (42,378,890 | ) | 835,142,190 | (15,485,714 | ) | ||||||||||
|
Adjusted Net Income
|
$ | 14,585,267 | $ | 15,606,420 | $ | 32,100,972 | $ | 44,676,910 | ||||||||
|
Weighted Average Shares Outstanding – Basic
|
60,679,257 | 60,559,827 | 60,627,142 | 60,753,752 | ||||||||||||
|
Weighted Average Shares Outstanding – Diluted
|
60,725,886 | 60,736,502 | 60,716,819 | 60,950,641 | ||||||||||||
|
Net (Loss) Income Per Common Share – Basic
|
$ | (5.33 | ) | $ | 0.96 | $ | (13.25 | ) | $ | 0. 99 | ||||||
|
Add:
|
||||||||||||||||
|
Impact of Selected Items, Net of Income Taxes
|
5.57 | (0.70 | ) | 13.78 | (0.25 | ) | ||||||||||
|
Adjusted Net Income Per Common Share – Basic
|
$ | 0.24 | $ | 0.26 | $ | 0.53 | $ | 0.74 | ||||||||
|
Net (Loss) Income Per Common Share – Diluted
|
$ | (5.32 | ) | $ | 0.95 | $ | (13.23 | ) | $ | 0.99 | ||||||
|
Add:
|
||||||||||||||||
|
Impact of Selected Items, Net of Income Taxes
|
5.56 | (0.69 | ) | 13.76 | (0.25 | ) | ||||||||||
|
Adjusted Net Income Per Common Share – Diluted
|
$ | 0.24 | $ | 0.26 | $ | 0.53 | $ | 0.74 | ||||||||
______________
|
(1)
|
For the 2015 columns, this represents tax impact using an estimated tax rate of 37.2% and 37.0% for the three and nine months ended September 30, 2015, respectively. These columns include a $120.1 million and $170.0 million adjustment for a change in valuation allowance for the three and nine months ended September 30, 2015, respectively. For the 2014 columns, this represents tax impact using an estimated tax rate of 37.7%.
|
Reconciliation of Adjusted EBITDA
|
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||
|
Net (Loss) Income
|
$ | (323,242,032 | ) | $ | 57,985,310 | $ | (803,041,218 | ) | $ | 60,162,624 | ||||||
|
Add:
|
||||||||||||||||
|
Interest Expense
|
16,154,160 | 10,624,246 | 42,278,400 | 30,850,004 | ||||||||||||
|
Income Tax Provision (Benefit)
|
(77,544 | ) | 35,050,000 | (202,424,154 | ) | 36,400,000 | ||||||||||
|
Depreciation, Depletion, Amortization and Accretion
|
31,670,479 | 45,646,232 | 113,629,323 | 123,959,402 | ||||||||||||
|
Impairment of Oil and Natural Gas Properties
|
354,422,654 | - | 996,815,713 | - | ||||||||||||
|
Non-Cash Share Based Compensation
|
1,141,241 | 736,971 | 3,221,715 | 2,022,180 | ||||||||||||
|
(Gain) Loss on the Mark-to-Market of Derivative Instruments
|
(8,408,682 | ) | (68,600,900 | ) | 59,115,913 | (25,433,684 | ) | |||||||||
|
Adjusted EBITDA
|
$ | 71,660,276 | $ | 81,441,859 | $ | 209,595,692 | $ | 227,960,526 | ||||||||