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| 8-K - 8-K - NORTHERN OIL & GAS, INC. | a8k-november82016.htm |
Exhibit 99.1
Northern Oil and Gas, Inc. Announces 2016 Third Quarter Results and Reaffirmation of $350 Million Borrowing Base under Revolving Credit Facility
WAYZATA, MINNESOTA - November 8, 2016 - Northern Oil and Gas, Inc. (NYSE MKT: NOG) today announced 2016 third quarter results and completion of the semi-annual redetermination of the borrowing base under Northern’s revolving credit facility.
HIGHLIGHTS
• | Production totaled 1,236,708 barrels of oil equivalent (“Boe”) for the third quarter, averaging 13,442 Boe per day, despite approximately 600 Boe per day of shut-in production during the quarter |
• | Oil and gas sales, including cash from settled derivatives, totaled $50.7 million for the third quarter |
• | Capital expenditures totaled $15.8 million during the third quarter, a reduction of 42.4% compared to the third quarter of 2015 |
• | Production expenses of $8.83 per Boe for the third quarter came in at the low end of management’s expense guidance |
• | Cash flow from operations for the first nine months of 2016 has exceeded capital expenditures, resulting in a $30 million reduction in debt since the beginning of the year |
• | On November 8, 2016, the borrowing base under Northern’s revolving credit facility was reaffirmed at $350 million, providing quarter-end liquidity of $233.3 million, composed of $3.3 million in cash and $230.0 million of revolving credit facility availability |
Northern’s adjusted net income for the third quarter was $2.4 million, or $0.04 per diluted share. GAAP net loss for the quarter was $45.6 million, or a loss of $0.74 per diluted share, which was impacted by a $43.8 million non-cash impairment charge and a $5.6 million loss on the mark-to-market of derivative instruments. Adjusted EBITDA for the third quarter was $33.0 million. See “Non-GAAP Financial Measures” below for additional information on these measures.
MANAGEMENT COMMENT
Northern has seen significant improvements in well productivity due to the widespread adoption of enhanced completion techniques and focus of drilling activity in the core of the play. The wells that Northern drilled and completed in 2015 are tracking an average type curve that would yield an estimated ultimate recovery (EUR) of 800,000 Boe, and early results for wells drilled and completed in 2016 are tracking a 900,000 Boe EUR average type curve. At the same time, average drilling and completion costs have declined materially, with average AFE costs of $7.1 million for wells consented during the first nine months of 2016. These improvements, together with Northern’s proactive management of its capital spending, have helped the company reduce debt by $30 million during 2016, which leaves Northern with a strong liquidity position following today’s reaffirmation of the borrowing base.
GUIDANCE
Northern continues to expect 2016 total production to be down approximately 15% compared to 2015 production levels. Management’s current expectations for fourth quarter 2016 operating metrics are as follows:
4th Quarter 2016 | ||
Operating Expenses: | ||
Production Expenses (per Boe) | $8.75 - $9.25 | |
Production Taxes (% of Oil & Gas Sales) | 10% | |
General and Admin. Expense (per Boe) | $3.50 - $4.00 | |
Average Differential to NYMEX WTI | ($8.00) to ($10.00) | |
LIQUIDITY
At September 30, 2016, Northern had $120 million in outstanding borrowings under its revolving credit facility, down from $150 million at December 31, 2015. On November 8th the borrowing base under the revolving credit facility was reaffirmed at $350 million, providing quarter-end liquidity of $233.3 million, composed of $3.3 million in cash and $230.0 million of revolving credit facility availability.
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, 2016.
Contract Period | Volume (Bbls) | Weighted Average Price (per Bbl) | ||
2016: | ||||
Q4 | 450,000 | $65.00 | ||
2017: | ||||
Q1 | 450,000 | $50.78 | ||
Q2 | 450,000 | $50.78 | ||
Q3 | 450,000 | $53.04 | ||
Q4 | 450,000 | $53.04 | ||
CAPITAL EXPENDITURES & DRILLING ACTIVITY
Third Quarter 2016 | ||
Capital Expenditures Incurred: | ||
Drilling, Completion & Capitalized Workover Expense | $13.8 million | |
Acreage | $1.6 million | |
Other | $0.4 million | |
Net Wells Added to Production | 1.8 | |
Net Producing Wells (Period-End) | 208.9 | |
Net Wells in Process (Period-End) | 9.4 | |
Weighted Average AFE for In-Process Wells (Period-End) | $7.4 million | |
For the first nine months of 2016, the weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in (consented) was $7.1 million.
ACREAGE
As of September 30, 2016, Northern controlled 156,074 net acres targeting the Williston Basin Bakken and Three Forks formations. As of September 30, 2016, approximately 83% of Northern’s North Dakota acreage position, and approximately 78% of Northern’s total acreage position, was developed, held by production or held by operations.
THIRD QUARTER 2016 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
Three Months Ended September 30, | |||||
2016 | 2015 | % Change | |||
Net Production: | |||||
Oil (Bbl) | 1,066,684 | 1,261,823 | (15) | ||
Natural Gas and NGLs (Mcf) | 1,020,143 | 1,174,721 | (13) | ||
Total (Boe) | 1,236,708 | 1,457,610 | (15) | ||
Average Daily Production: | |||||
Oil (Bbl) | 11,594 | 13,715 | (15) | ||
Natural Gas and NGL (Mcf) | 11,089 | 12,769 | (13) | ||
Total (Boe) | 13,442 | 15,844 | (15) | ||
Average Sales Prices: | |||||
Oil (per Bbl) | $ 37.26 | $ 38.26 | (3) | ||
Effect of Gain on Settled Derivatives on Average Price (per Bbl) | 8.46 | 34.04 | (75) | ||
Oil Net of Settled Derivatives (per Bbl) | 45.72 | 72.30 | (37) | ||
Natural Gas and NGLs (per Mcf) | 1.93 | 1.28 | 51 | ||
Realized Price on a Boe Basis Including all Realized Derivative Settlements | 41.03 | 63.62 | (36) | ||
Costs and Expenses (per Boe): | |||||
Production Expenses | $ 8.83 | $ 8.62 | 2 | ||
Production Taxes | 3.27 | 3.46 | (5) | ||
General and Administrative Expense | 1.70 | 3.17 | (46) | ||
Depletion, Depreciation, Amortization and Accretion | 11.08 | 21.72 | (49) | ||
Net Producing Wells at Period End | 208.9 | 201.9 | |||
Oil and Natural Gas Sales
In the third quarter of 2016, oil, natural gas and NGL sales, excluding the effect of settled derivatives, decreased 16% as compared to the third quarter of 2015, driven by a 15% decrease in production and a 1% decrease in realized prices, excluding the effect of settled derivatives. Production in the third quarter of 2016 was negatively impacted by approximately 600 Boe per day due to wells shut-in while completion activities occurred on offsetting locations. The lower average realized price in the third quarter of 2016 as compared to the same period in 2015 was principally driven by lower average NYMEX oil prices, which was partially offset by a lower oil price differential. Oil price differential during the third quarter of 2016 was $7.68 per barrel, as compared to $8.24 per barrel in the third quarter of 2015.
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.
Three Months Ended September 30, | |||||||
2016 | 2015 | ||||||
(in millions) | |||||||
Derivative Instruments (Hedges): | |||||||
Cash Derivative Settlements | $ | 9 | $ | 43 | |||
Non-Cash Mark-to-Market of Derivative Instruments | (5.6 | ) | 8.4 | ||||
Gain on Derivative Instruments, Net | $ | 3.4 | $ | 51.4 | |||
Northern’s average realized price (including all cash derivative settlements) received during the third quarter of 2016 was $41.03 per Boe compared to $63.62 per Boe in the third quarter of 2015. The gain on settled derivatives increased Northern’s average realized price per Boe by $7.30 in the third quarter of 2016 and by $29.47 in the third quarter of 2015.
As a result of forward oil price changes, Northern recognized a non-cash mark-to-market derivative loss of $5.6 million in the third quarter of 2016, compared to a gain of $8.4 million in the third quarter of 2015.
Production Expenses
Production expenses were $10.9 million in the third quarter of 2016, compared to $12.6 million in the third quarter of 2015. On a per unit basis, production expenses increased from $8.62 per Boe in the third quarter of 2015 to $8.83 per Boe in the third quarter of 2016 due to a 15% decline in production levels over which fixed costs are spread, partially offset by a reduction in the aggregate dollar amount of production expenses. Although the total producing well count increased by 3%, aggregate production expenses declined due to reductions in contract labor and maintenance costs.
Production Taxes
Lower production levels and commodity prices in the third quarter of 2016 as compared to the third quarter of 2015 has decreased our crude oil and natural gas sales, which has lowered the taxable base that is used to calculate production taxes. Production taxes were $4.0 million in the third quarter of 2016 compared to $5.0 million in the third quarter of 2015. As a percentage of oil and natural gas sales, our production taxes were 9.7% and 10.1% in the third quarter of 2016 and 2015, respectively. This decrease in production tax rates as a percentage of oil and gas sales in the third quarter of 2016 is due to a lower oil production tax rate in North Dakota, which dropped to 10% beginning in 2016.
General and Administrative Expense
General and administrative expense was $2.1 million in the third quarter of 2016 compared to $4.6 million in the third quarter of 2015. A $2.2 million reduction in compensation expense was in large part due to the termination of the Company's chief executive officer in the third quarter of 2016, which resulted in the reversal of non-cash share-based compensation expense of approximately $1.8 million and lower salary expense of $0.1 million when compared to the third quarter of 2015. Cash general and administrative expenses in the third quarter of 2016 amounted to $2.8 million, a 19% decline compared to the third quarter of 2015.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $13.7 million in the third quarter of 2016 compared to $31.7 million in the third quarter of 2015. Depletion expense, the largest component of DD&A, decreased by $18.0 million in the third quarter of 2016 as compared to the third quarter of 2015. On a per unit basis, depletion expense was $10.96 per Boe in the third quarter of 2016 compared to $21.61 per Boe in the third quarter of 2015. The year-over-year decrease was due to the impairment of oil and gas properties in 2015 and 2016, which has lowered the depletable base.
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 our properties, we recorded a non-cash ceiling test impairment of $43.8 million in the third quarter of 2016 and $354.4 million in the third quarter of 2015. The impairment charge affected our reported net income but did not reduce our cash flow.
Interest Expense
Interest expense, net of capitalized interest, was $16.1 million in the third quarter of 2016, compared to $16.2 million in the third quarter of 2015. The decrease in interest expense for the third quarter of 2016 as compared to the third quarter of 2015 was primarily due to a decrease in average borrowings outstanding.
Income Tax Provision
Northern recognized no income tax benefit during the third quarter of 2016 as compared to an income tax benefit of $0.1 million in the third quarter of 2015.
Net Income
Northern recorded a net loss of $45.6 million, or a loss of $0.74 per diluted share, for the third quarter of 2016, compared to a net loss of $323.2 million, or a loss of $5.33 per diluted share, for the third quarter of 2015. The net loss in the third quarter of 2016 was impacted by lower realized commodity prices and production levels, the non-cash impairment of oil and natural gas properties, 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 2016 was $2.4 million (representing $0.04 per diluted share), compared to $14.6 million (representing $0.24 per diluted share) for the third quarter of 2015. Northern defines Adjusted Net Income as net income excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) debt issuance cost write-off, net of tax, (iii) restructuring costs, net of tax and (iv) impairment of oil and natural gas properties, net of tax.
Adjusted EBITDA for the third quarter of 2016 was $33.0 million, compared to Adjusted EBITDA of $71.7 million for the third quarter of 2015. The decrease in Adjusted EBITDA is primarily due to the lower average NYMEX oil prices, declining production levels, and reduced hedging levels in the third quarter of 2016 compared to the third quarter of 2015. 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, (vi) debt issuance cost write-off and (vii) 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.
THIRD QUARTER 2016 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 Wednesday November 9, 2016 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: 4937592 - Northern Oil and Gas, Inc. Third Quarter 2016 Earnings Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code: 4937592 - Replay will be available through November 16, 2016
UPCOMING CONFERENCE SCHEDULE
Capital One Securities 11th Annual Energy Conference
December 6 - 8, 2016, 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, CFA
Executive Vice President
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, 2016 AND 2015
(UNAUDITED)
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
REVENUES | |||||||||||||||
Oil and Gas Sales | $ | 41,719,194 | $ | 49,779,903 | $ | 112,614,382 | $ | 163,298,384 | |||||||
Gain (Loss) on Derivative Instruments, Net | 3,381,564 | 51,366,762 | (3,677,502 | ) | 54,818,997 | ||||||||||
Other Revenue | 8,650 | 9,887 | 22,989 | 27,004 | |||||||||||
Total Revenues | 45,109,408 | 101,156,552 | 108,959,869 | 218,144,385 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Production Expenses | 10,920,651 | 12,567,423 | 33,961,883 | 40,331,314 | |||||||||||
Production Taxes | 4,045,291 | 5,048,227 | 11,032,903 | 17,333,123 | |||||||||||
General and Administrative Expense | 2,098,293 | 4,614,771 | 11,021,970 | 13,224,012 | |||||||||||
Depletion, Depreciation, Amortization and Accretion | 13,698,020 | 31,670,479 | 47,720,972 | 113,629,323 | |||||||||||
Impairment of Oil and Natural Gas Properties | 43,820,791 | 354,422,654 | 237,012,834 | 996,815,713 | |||||||||||
Total Expenses | 74,583,046 | 408,323,554 | 340,750,562 | 1,181,333,485 | |||||||||||
LOSS FROM OPERATIONS | (29,473,638 | ) | (307,167,002 | ) | (231,790,693 | ) | (963,189,100 | ) | |||||||
OTHER INCOME (EXPENSE) | |||||||||||||||
Interest Expense, Net of Capitalization | (16,145,440 | ) | (16,154,160 | ) | (48,290,447 | ) | (42,278,400 | ) | |||||||
Write-off of Debt Issuance Costs | — | — | (1,089,507 | ) | — | ||||||||||
Other Income | 183 | 1,586 | 7,337 | 2,128 | |||||||||||
Total Other Income (Expense) | (16,145,257 | ) | (16,152,574 | ) | (49,372,617 | ) | (42,276,272 | ) | |||||||
LOSS BEFORE INCOME TAXES | (45,618,895 | ) | (323,319,576 | ) | (281,163,310 | ) | (1,005,465,372 | ) | |||||||
INCOME TAX BENEFIT | — | (77,544 | ) | — | (202,424,154 | ) | |||||||||
NET LOSS | $ | (45,618,895 | ) | $ | (323,242,032 | ) | $ | (281,163,310 | ) | $ | (803,041,218 | ) | |||
Net Loss Per Common Share – Basic | $ | (0.74 | ) | $ | (5.33 | ) | $ | (4.60 | ) | $ | (13.25 | ) | |||
Net Loss Per Common Share – Diluted | $ | (0.74 | ) | $ | (5.33 | ) | $ | (4.60 | ) | $ | (13.25 | ) | |||
Weighted Average Shares Outstanding – Basic | 61,237,627 | 60,679,257 | 61,127,577 | 60,627,142 | |||||||||||
Weighted Average Shares Outstanding – Diluted | 61,237,627 | 60,679,257 | 61,127,577 | 60,627,142 | |||||||||||
CONDENSED BALANCE SHEETS
SEPTEMBER 30, 2016 AND DECEMBER 31, 2015
September 30, 2016 (unaudited) | December 31, 2015 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and Cash Equivalents | $ | 3,319,021 | $ | 3,390,389 | |||
Trade Receivables, Net | 32,856,099 | 51,445,026 | |||||
Advances to Operators | 1,733,051 | 1,689,879 | |||||
Prepaid and Other Expenses | 1,200,717 | 892,867 | |||||
Derivative Instruments | 7,212,947 | 64,611,558 | |||||
Total Current Assets | 46,321,835 | 122,029,719 | |||||
Property and Equipment: | |||||||
Oil and Natural Gas Properties, Full Cost Method of Accounting | |||||||
Proved | 2,392,372,802 | 2,336,757,089 | |||||
Unproved | 4,822,789 | 10,007,529 | |||||
Other Property and Equipment | 1,871,314 | 1,837,469 | |||||
Total Property and Equipment | 2,399,066,905 | 2,348,602,087 | |||||
Less – Accumulated Depreciation, Depletion and Impairment | (2,043,702,564 | ) | (1,759,281,704 | ) | |||
Total Property and Equipment, Net | 355,364,341 | 589,320,383 | |||||
Derivative Instruments | 20,166 | — | |||||
Deferred Income Taxes (Note 9) | — | — | |||||
Other Noncurrent Assets, Net | 8,665,794 | 10,080,846 | |||||
Total Assets | $ | 410,372,136 | $ | 721,430,948 | |||
LIABILITIES AND STOCKHOLDERS’ DEFICIT | |||||||
Current Liabilities: | |||||||
Accounts Payable | $ | 47,759,558 | $ | 65,319,170 | |||
Accrued Expenses | 5,201,185 | 7,893,975 | |||||
Accrued Interest | 18,670,814 | 4,713,232 | |||||
Derivative Instruments | 707,703 | — | |||||
Asset Retirement Obligations | 243,698 | 188,770 | |||||
Total Current Liabilities | 72,582,958 | 78,115,147 | |||||
Long-term Debt, Net | 807,788,710 | 835,290,329 | |||||
Derivative Instruments | 49,153 | — | |||||
Asset Retirement Obligations | 6,011,773 | 5,627,586 | |||||
Total Liabilities | $ | 886,432,594 | $ | 919,033,062 | |||
Commitments and Contingencies (Note 8) | |||||||
STOCKHOLDERS’ DEFICIT | |||||||
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding | — | — | |||||
Common Stock, Par Value $.001; 142,500,000 Authorized (9/30/2016 – 63,029,971 Shares Outstanding and 12/31/2015 – 63,120,384 Shares Outstanding) | 63,030 | 63,120 | |||||
Additional Paid-In Capital | 442,926,076 | 440,221,018 | |||||
Retained Deficit | (919,049,564 | ) | (637,886,252 | ) | |||
Total Stockholders’ Deficit | (476,060,458 | ) | (197,602,114 | ) | |||
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT | $ | 410,372,136 | $ | 721,430,948 | |||
Reconciliation of Adjusted Net Income
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
Net Loss | $ | (45,618,895 | ) | $ | (323,242,032 | ) | $ | (281,163,310 | ) | $ | (803,041,218 | ) | |||
Add: | |||||||||||||||
Impact of Selected Items: | |||||||||||||||
(Gain) Loss on the Mark-to-Market of Derivative Instruments | 5,645,586 | (8,408,682 | ) | 58,135,302 | 59,115,913 | ||||||||||
Write-off of Debt Issuance Costs | — | — | 1,089,507 | — | |||||||||||
Restructuring Costs | — | 523,487 | — | 523,487 | |||||||||||
Impairment of Oil and Natural Gas Properties | 43,820,791 | 354,422,654 | 237,012,834 | 996,815,713 | |||||||||||
Selected Items, Before Income Taxes | 49,466,377 | 346,537,459 | 296,237,643 | 1,056,455,113 | |||||||||||
Income Tax of Selected Items(1) | (1,494,741 | ) | (8,710,160 | ) | (5,572,304 | ) | (221,312,923 | ) | |||||||
Selected Items, Net of Income Taxes | 47,971,636 | 337,827,299 | 290,665,339 | 835,142,190 | |||||||||||
Adjusted Net Income | $ | 2,352,741 | $ | 14,585,267 | $ | 9,502,029 | $ | 32,100,972 | |||||||
Weighted Average Shares Outstanding – Basic | 61,237,627 | 60,679,257 | 61,127,577 | 60,627,142 | |||||||||||
Weighted Average Shares Outstanding – Diluted | 61,771,363 | 60,725,886 | 61,825,191 | 60,716,819 | |||||||||||
Net Loss Per Common Share – Basic | $ | (0.74 | ) | $ | (5.33 | ) | $ | (4.60 | ) | $ | (13.25 | ) | |||
Add: | |||||||||||||||
Impact of Selected Items, Net of Income Taxes | 0.78 | 5.57 | 4.76 | 13.78 | |||||||||||
Adjusted Net Income Per Common Share – Basic | $ | 0.04 | $ | 0.24 | $ | 0.16 | $ | 0.53 | |||||||
Net Loss Per Common Share – Diluted | $ | (0.74 | ) | $ | (5.32 | ) | $ | (4.55 | ) | $ | (13.23 | ) | |||
Add: | |||||||||||||||
Impact of Selected Items, Net of Income Taxes | 0.78 | 5.56 | 4.70 | 13.76 | |||||||||||
Adjusted Net Income Per Common Share – Diluted | $ | 0.04 | $ | 0.24 | $ | 0.15 | $ | 0.53 | |||||||
______________
(1) | For the 2016 columns, this represents a tax impact using an estimated tax rate of 38.8% and 37.0% for the three and nine months ended September 30, 2016, respectively, which includes a $17.7 million and $104.0 million adjustment for a change in valuation allowance for the three and nine months ended September 30, 2016, respectively. For the 2015 columns, this represents a tax impact using an estimated tax rate of 37.2% and 37.0% for the three and nine months ended September 30, 2015, respectively, which includes 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. |
Reconciliation of Adjusted EBITDA
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
Net Loss | $ | (45,618,895 | ) | $ | (323,242,032 | ) | $ | (281,163,310 | ) | $ | (803,041,218 | ) | |||
Add: | |||||||||||||||
Interest Expense | 16,145,440 | 16,154,160 | 48,290,447 | 42,278,400 | |||||||||||
Income Tax Benefit | — | (77,544 | ) | — | (202,424,154 | ) | |||||||||
Depreciation, Depletion, Amortization and Accretion | 13,698,020 | 31,670,479 | 47,720,972 | 113,629,323 | |||||||||||
Impairment of Oil and Natural Gas Properties | 43,820,791 | 354,422,654 | 237,012,834 | 996,815,713 | |||||||||||
Non-Cash Share Based Compensation | (712,677 | ) | 1,141,241 | 2,308,793 | 3,221,715 | ||||||||||
Write-off of Debt Issuance Costs | — | — | 1,089,507 | — | |||||||||||
(Gain) Loss on the Mark-to-Market of Derivative Instruments | 5,645,586 | (8,408,682 | ) | 58,135,302 | 59,115,913 | ||||||||||
Adjusted EBITDA | $ | 32,978,265 | $ | 71,660,276 | $ | 113,394,545 | $ | 209,595,692 | |||||||