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| 8-K - 8-K - NOVEMBER 8, 2017 - NORTHERN OIL & GAS, INC. | a8-knovember82017.htm |
Exhibit 99.1
Northern Oil and Gas, Inc. Announces 2017 Third Quarter Results
MINNEAPOLIS, MINNESOTA - November 8, 2017 - Northern Oil and Gas, Inc. (NYSE American: NOG) today announced 2017 third quarter results, increased annual production guidance and lowered operating expense expectations for the fourth quarter.
HIGHLIGHTS
• | Daily production increased 11% sequentially to average 15,321 barrels of oil equivalent (“Boe”) per day in the third quarter, for a total of 1,409,501 Boe. |
• | 3.6 net wells were added to production during the third quarter and wells in process ended the quarter at 18.0 net wells, the highest level since 2014. |
• | Northern now expects average daily production for 2017 to increase between 5% - 6% compared to 2016 and expects to add approximately 14.0 net wells to production for the year. |
• | Northern closed a new credit facility on November 1st that provides liquidity of approximately $235 million, comprised of $135 million of cash on hand and $100 million of delayed draw term loan availability. |
Northern’s GAAP net loss for the third quarter of 2017 was $16.1 million. Adjusted net income for the quarter was $2.2 million. Adjusted EBITDA for the quarter was $35.7 million. See “Non-GAAP Financial Measures” below for additional information on these measures.
MANAGEMENT COMMENT
“It is validating to see our efforts over the last year come to fruition and to see the momentum we have generated as we approach 2018,” commented Northern’s Interim CEO and CFO, Tom Stoelk. “Our focus on capital allocation is showing up in better well productivity and increased production levels, and our wells in process are concentrated among operators getting some of the best results in the basin. Our new credit facility with TPG Sixth Street Partners has extended our debt maturity and increased our access to capital. This additional liquidity combined with Northern’s high-quality assets and returns-focused capital allocation strategy provides a solid foundation to increase shareholder value.”
GUIDANCE
Northern is increasing its 2017 guidance and now expects average daily production for 2017 to increase between 5% - 6% compared to 2016. As a result of increased activity on its acreage Northern now expects to add approximately 14 net wells to production for the year. This coupled with the growth in Northern’s wells in process inventory resulted in a revised annual capital budget of $130 million for 2017.
Management’s current expectations for fourth quarter of 2017 operating metrics are as follows:
Operating Expenses: | Fourth Quarter 2017 | |
Production Expenses (per Boe) | $9.00 - $9.25 | |
Production Taxes (% of Oil & Gas Sales) | 9.4% | |
General and Administrative Expense (per Boe) | $3.00 - $3.25 | |
Average Differential to NYMEX WTI | $6.00 - $7.00 | |
LIQUIDITY
At September 30, 2017, Northern had $155.0 million in outstanding borrowings under its revolving credit facility. On November 1, 2017, Northern announced that it had closed an agreement with TPG Sixth Street Partners for a new five year $400 million first lien credit facility. At closing, an initial amount of $300 million was funded and a portion of these proceeds were used to retire and repay the old revolving credit facility. Based on this new credit facility, Northern had available liquidity of approximately $235 million as of November 1, 2017, comprised of $135 million of cash on hand and $100 million of delayed draw term loan 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 derivative contracts scheduled to settle after September 30, 2017.
Swaps | Collars | |||||||
Contract Period | Volume (Bbls) | Weighted Average Price (per Bbl) | Volume (Bbls) | Weighted Average Floor - Ceiling Prices (per Bbl) | ||||
2017: | ||||||||
4Q | 629,500 | $53.61 | 75,000 | $50.00 - $60.06 | ||||
2018: | ||||||||
1Q | 825,000 | $53.08 | — | — | ||||
2Q | 829,000 | $53.09 | — | — | ||||
3Q | 753,000 | $53.42 | — | — | ||||
4Q | 643,000 | $53.54 | — | — | ||||
2019: | ||||||||
1Q | 315,000 | $51.21 | — | — | ||||
2Q | 318,500 | $51.21 | — | — | ||||
3Q | 322,000 | $51.21 | — | — | ||||
4Q | 322,000 | $51.21 | — | — | ||||
2020: | ||||||||
1Q | 182,000 | $49.76 | — | — | ||||
2Q | 182,000 | $49.76 | — | — | ||||
3Q | 184,000 | $49.76 | — | — | ||||
4Q | 184,000 | $49.76 | — | — | ||||
CAPITAL EXPENDITURES & DRILLING ACTIVITY
Three Months Ended September 30, 2017 | ||
Capital Expenditures Incurred: | ||
Drilling, Completion & Capitalized Workover Expense | $38.2 million | |
Acreage | $2.1 million | |
Other | $0.4 million | |
Net Wells Added to Production | 3.6 | |
Net Producing Wells (Period-End) | 222.3 | |
Net Wells in Process (Period-End) | 18.0 | |
Weighted Average AFE for In-Process Wells (Period-End) | $7.4 million | |
The weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in (consented) was $7.6 million for the third quarter of 2017, and $7.3 million for the first nine months of 2017.
ACREAGE
As of September 30, 2017, Northern has leased approximately 145,749 net acres targeting the Williston Basin Bakken and Three Forks formations. As of September 30, 2017, approximately 87% of Northern’s North Dakota acreage position, and approximately 86% of Northern’s total acreage position was developed, held by production or held by operations.
THIRD QUARTER 2017 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
Three Months Ended September 30, | ||||||||||
2017 | 2016 | % Change | ||||||||
Net Production: | ||||||||||
Oil (Bbl) | 1,186,814 | 1,066,684 | 11 | % | ||||||
Natural Gas and NGLs (Mcf) | 1,336,124 | 1,020,143 | 31 | % | ||||||
Total (Boe) | 1,409,501 | 1,236,708 | 14 | % | ||||||
Average Daily Production: | ||||||||||
Oil (Bbl) | 12,900 | 11,594 | 11 | % | ||||||
Natural Gas and NGLs (Mcf) | 14,523 | 11,089 | 31 | % | ||||||
Total (Boe) | 15,321 | 13,442 | 14 | % | ||||||
Net Sales: | ||||||||||
Oil Sales | $ | 50,309,088 | $ | 39,747,741 | 27 | % | ||||
Natural Gas and NGL Sales | 3,948,503 | 1,971,453 | 100 | % | ||||||
Gain (Loss) on Derivative Instruments, Net | (12,663,253 | ) | 3,381,564 | (474 | )% | |||||
Other Revenue | 4,321 | 8,650 | (50 | )% | ||||||
Total Revenues | 41,598,659 | 45,109,408 | (8 | )% | ||||||
Average Sales Prices: | ||||||||||
Oil (per Bbl) | $ | 42.39 | $ | 37.26 | 14 | % | ||||
Effect of Gain on Settled Derivatives on Average Price (per Bbl) | 2.86 | 8.46 | (66 | )% | ||||||
Oil Net of Settled Derivatives (per Bbl) | 45.25 | 45.72 | (1 | )% | ||||||
Natural Gas and NGLs (per Mcf) | 2.96 | 1.93 | 53 | % | ||||||
Realized Price on a Boe Basis Including all Realized Derivative Settlements | 40.90 | 41.03 | — | % | ||||||
Operating Expenses: | ||||||||||
Production Expenses | $ | 12,605,513 | $ | 10,920,651 | 15 | % | ||||
Production Taxes | 5,064,761 | 4,045,291 | 25 | % | ||||||
General and Administrative Expense | 7,985,719 | 2,098,293 | 281 | % | ||||||
Depletion, Depreciation, Amortization and Accretion | 15,357,685 | 13,698,020 | 12 | % | ||||||
Costs and Expenses (per Boe): | ||||||||||
Production Expenses | $ | 8.94 | $ | 8.83 | 1 | % | ||||
Production Taxes | 3.59 | 3.27 | 10 | % | ||||||
General and Administrative Expense | 5.67 | 1.70 | 234 | % | ||||||
Depletion, Depreciation, Amortization and Accretion | 10.90 | 11.08 | (2 | )% | ||||||
Net Producing Wells at Period End | 222.3 | 208.9 | 6 | % | ||||||
Oil and Natural Gas Sales
In the third quarter of 2017, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 30% as compared to the third quarter of 2016, driven by a 14% increase in realized prices, excluding the effect of settled derivatives, and a 14% increase in production. The higher average realized price in the third quarter of 2017 as compared to the same period in 2016 was principally driven by higher average NYMEX oil and natural gas prices and a lower oil price differential. Oil price differential during the third quarter of 2017 was $6.22 per barrel, as compared to $7.68 per barrel in the third quarter of 2016.
Derivative Instruments (Hedges)
Northern enters into derivative instruments to manage the price risk attributable to future oil production. Gain (loss) on derivative instruments, net was a loss of $12.7 million in the third quarter of 2017, compared to a gain of $3.4 million in the third quarter of 2016. 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, | |||||||
2017 | 2016 | ||||||
Cash Received (Paid) on Derivatives | $ | 3,395,117 | $ | 9,027,150 | |||
Non-Cash Gain (Loss) on Derivatives | (16,058,370 | ) | (5,645,586 | ) | |||
Gain (Loss) on Derivative Instruments, Net | $ | (12,663,253 | ) | $ | 3,381,564 | ||
The average NYMEX oil price for the third quarter of 2017 was $48.20 compared to $44.94 for the third quarter of 2016. Northern’s average realized price (including all cash derivative settlements) in the third quarter of 2017 was $40.90 per Boe compared to $41.03 per Boe in the third quarter of 2016. The gain (loss) on settled derivatives increased the average realized price per Boe by $2.41 in the third quarter of 2017 and increased the average realized price per Boe by $7.30 in the third quarter of 2016.
Production Expenses
Production expenses were $12.6 million in the third quarter of 2017 compared to $10.9 million in the third quarter of 2016. On a per unit basis, production expenses increased to $8.94 per Boe in the third quarter of 2017, compared to $8.83 per Boe in the third quarter of 2016. On an absolute dollar basis, the increase in production expenses in the third quarter of 2017 as compared to the third quarter of 2016 was primarily due to higher processing costs and salt water disposal costs and a 14% increase in production, as well as a 6% increase in the total number of net producing wells.
Production Taxes
Production taxes were $5.1 million in the third quarter of 2017 compared to $4.0 million in the third quarter of 2016. The increase is due to higher commodity prices and higher production levels, which increased oil and natural gas sales in the third quarter of 2017 as compared to the third quarter of 2016. As a percentage of oil and natural gas sales, production taxes were 9.3% and 9.7% in the third quarter of 2017 and 2016, respectively. This decrease in production tax rates as a percentage of oil and natural gas sales is due to a change in sales mix. Production taxes on natural gas and NGL sales are at a lower percentage than that of crude oil sales. Crude oil sales represented 93% of oil and natural gas sales in the third quarter of 2017 compared to 95% in the third quarter of 2016.
General and Administrative Expense
General and administrative expenses were $8.0 million in the third quarter of 2017 compared to $2.1 million in the third quarter of 2016. The increase was due in part to a $3.6 million charge in connection with a settlement agreement with our former chief executive officer in the third quarter of 2017, and a $0.9 million increase in legal and professional expenses compared to the third quarter of 2016, partially offset by a $0.4 million decrease in cash compensation expense due primarily to reduced incentive compensation. In addition, general and administrative expense in the third quarter of 2016 was reduced by a $1.8 million reversal of non-cash share based compensation expense in connection with the termination of the employment of our former chief executive officer.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $15.4 million in the third quarter of 2017 compared to $13.7 million in the third quarter of 2016. Depletion expense, the largest component of DD&A, increased by $1.6 million in the third quarter of 2017 compared to the third quarter of 2016. The aggregate increase in depletion expense was driven by a 14% increase in production levels which was partially offset by a 2% decrease in the depletion rate per Boe. On a per unit basis, depletion expense was $10.77 per Boe in the third quarter of 2017 compared to $10.96 per Boe in the third quarter of 2016. The 2017 depletion rate per Boe was lower due to the impairment of oil and natural gas properties in 2016, which lowered the depletable base. Depreciation, amortization and accretion was $0.2 million and $0.1 million in the third quarter of 2017 and 2016, respectively.
Impairment of Oil and Natural Gas Properties
No impairment of oil and natural gas properties was recorded in the third quarter of 2017. As a result of low prevailing commodity prices and their effect on the proved reserve values of its properties, Northern recorded a non-cash ceiling test impairment of $43.8 million for the third quarter of 2016. The impairment charge affected Northern’s reported net income in 2016 but did not reduce cash flow.
Interest Expense
Interest expense, net of capitalized interest, was $16.7 million for the third quarter of 2017 compared to $16.1 million in the third quarter of 2016. The increase in interest expense for the third quarter of 2017 compared to the third quarter of 2016 was primarily due to higher levels of debt between periods.
Income Tax Provision
During the third quarter of 2017 and 2016, no income tax expense (benefit) was recorded on the income (loss) before income taxes due to the valuation allowance placed on the net deferred tax asset.
Non-GAAP Financial Measures
Adjusted Net Income for the third quarter of 2017 was $2.2 million (representing approximately $0.04 per diluted share), compared to $2.4 million (representing approximately $0.04 per diluted share) for the third quarter of 2016. The decrease in Adjusted Net Income is primarily due to higher operating expenses which was partially offset by higher production levels. Northern defines Adjusted Net Income as net income (loss) excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) impairment of oil and natural gas properties, net of tax, (iii) write-off of debt issuance costs, net of tax, and (iv) certain legal settlements, net of tax.
Adjusted EBITDA for the third quarter of 2017 was $35.7 million, compared to Adjusted EBITDA of $33.0 million for the third quarter of 2016. The increase in Adjusted EBITDA is due to significantly higher production levels which were partially offset by higher operating expenses. Northern defines Adjusted EBITDA as net income (loss) 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) write-off of debt issuance costs 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 2017 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 9, 2017 at 9:00 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: 3696446 - Northern Oil and Gas, Inc. Third Quarter 2017 Conference Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code: 3696446 - Replay will be available through November 16, 2017
UPCOMING CONFERENCE SCHEDULE
Capital One Securities, Inc. 12th Annual Energy Conference
December 5 - 7, 2017, 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,” “continue,” “anticipate,” “target,” “could,” “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 or access 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, 2017 AND 2016
(UNAUDITED)
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
REVENUES | |||||||||||||||
Oil and Gas Sales | $ | 54,257,591 | $ | 41,719,194 | $ | 151,486,819 | $ | 112,614,382 | |||||||
Gain (Loss) on Derivative Instruments, Net | (12,663,253 | ) | 3,381,564 | 20,810,662 | (3,677,502 | ) | |||||||||
Other Revenue | 4,321 | 8,650 | 19,911 | 22,989 | |||||||||||
Total Revenues | 41,598,659 | 45,109,408 | 172,317,392 | 108,959,869 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Production Expenses | 12,605,513 | 10,920,651 | 36,417,402 | 33,961,883 | |||||||||||
Production Taxes | 5,064,761 | 4,045,291 | 13,965,800 | 11,032,903 | |||||||||||
General and Administrative Expenses | 7,985,719 | 2,098,293 | 15,911,802 | 11,021,970 | |||||||||||
Depletion, Depreciation, Amortization and Accretion | 15,357,685 | 13,698,020 | 41,868,280 | 47,720,972 | |||||||||||
Impairment of Oil and Natural Gas Properties | — | 43,820,791 | — | 237,012,834 | |||||||||||
Total Operating Expenses | 41,013,678 | 74,583,046 | 108,163,284 | 340,750,562 | |||||||||||
INCOME (LOSS) FROM OPERATIONS | 584,981 | (29,473,638 | ) | 64,154,108 | (231,790,693 | ) | |||||||||
OTHER INCOME (EXPENSE) | |||||||||||||||
Interest Expense, Net of Capitalization | (16,672,632 | ) | (16,145,440 | ) | (49,404,601 | ) | (48,290,447 | ) | |||||||
Write-off of Debt Issuance Costs | — | — | (95,135 | ) | (1,089,507 | ) | |||||||||
Other Income | 184 | 183 | 545 | 7,337 | |||||||||||
Total Other Income (Expense) | (16,672,448 | ) | (16,145,257 | ) | (49,499,191 | ) | (49,372,617 | ) | |||||||
INCOME (LOSS) BEFORE INCOME TAXES | (16,087,467 | ) | (45,618,895 | ) | 14,654,917 | (281,163,310 | ) | ||||||||
INCOME TAX PROVISION (BENEFIT) | — | — | — | — | |||||||||||
NET INCOME (LOSS) | $ | (16,087,467 | ) | $ | (45,618,895 | ) | $ | 14,654,917 | $ | (281,163,310 | ) | ||||
Net Income (Loss) Per Common Share – Basic | $ | (0.26 | ) | $ | (0.74 | ) | $ | 0.24 | $ | (4.60 | ) | ||||
Net Income (Loss) Per Common Share – Diluted | $ | (0.26 | ) | $ | (0.74 | ) | $ | 0.24 | $ | (4.60 | ) | ||||
Weighted Average Shares Outstanding – Basic | 61,843,377 | 61,237,627 | 61,645,920 | 61,127,577 | |||||||||||
Weighted Average Shares Outstanding – Diluted | 61,843,377 | 61,237,627 | 61,991,292 | 61,127,577 | |||||||||||
CONDENSED BALANCE SHEETS
SEPTEMBER 30, 2017 AND DECEMBER 31, 2016
September 30, 2017 (unaudited) | December 31, 2016 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and Cash Equivalents | $ | 6,776,667 | $ | 6,486,098 | |||
Accounts Receivable, Net | 39,179,206 | 35,840,042 | |||||
Advances to Operators | 1,211,517 | 1,577,204 | |||||
Prepaid and Other Expenses | 2,278,674 | 1,584,129 | |||||
Derivative Instruments | 2,622,120 | 4,517 | |||||
Income Tax Receivable | 1,402,179 | 1,402,179 | |||||
Total Current Assets | 53,470,363 | 46,894,169 | |||||
Property and Equipment: | |||||||
Oil and Natural Gas Properties, Full Cost Method of Accounting | |||||||
Proved | 2,527,686,215 | 2,428,595,048 | |||||
Unproved | 2,204,991 | 2,623,802 | |||||
Other Property and Equipment | 981,303 | 977,349 | |||||
Total Property and Equipment | 2,530,872,509 | 2,432,196,199 | |||||
Less – Accumulated Depreciation, Depletion and Impairment | (2,097,463,246 | ) | (2,055,987,766 | ) | |||
Total Property and Equipment, Net | 433,409,263 | 376,208,433 | |||||
Derivative Instruments | 817,418 | — | |||||
Deferred Income Taxes (Note 9) | — | — | |||||
Other Noncurrent Assets, Net | 6,668,836 | 8,430,359 | |||||
Total Assets | $ | 494,365,880 | $ | 431,532,961 | |||
LIABILITIES AND STOCKHOLDERS’ DEFICIT | |||||||
Current Liabilities: | |||||||
Accounts Payable | $ | 81,150,980 | $ | 56,146,847 | |||
Accrued Expenses | 10,041,145 | 6,094,938 | |||||
Accrued Interest | 18,693,327 | 4,682,894 | |||||
Derivative Instruments | 4,741 | 10,001,564 | |||||
Asset Retirement Obligations | 577,886 | 517,423 | |||||
Current Maturities of Long-term Debt | 155,000,000 | — | |||||
Total Current Liabilities | 265,468,079 | 77,443,666 | |||||
Long-term Debt, Net | 691,118,074 | 832,625,125 | |||||
Derivative Instruments | — | 1,738,329 | |||||
Asset Retirement Obligations | 8,243,001 | 6,990,877 | |||||
Other Noncurrent Liabilities | 141,152 | 156,632 | |||||
Total Liabilities | $ | 964,970,306 | $ | 918,954,629 | |||
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 (9/30/2017 – 63,822,028 Shares Outstanding and 12/31/2016 – 63,259,781 Shares Outstanding) | 63,822 | 63,260 | |||||
Additional Paid-In Capital | 446,056,796 | 443,895,032 | |||||
Retained Deficit | (916,725,044 | ) | (931,379,960 | ) | |||
Total Stockholders’ Deficit | (470,604,426 | ) | (487,421,668 | ) | |||
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT | $ | 494,365,880 | $ | 431,532,961 | |||
Reconciliation of Adjusted Net Income
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Net Income (Loss) | $ | (16,087,467 | ) | $ | (45,618,895 | ) | $ | 14,654,917 | $ | (281,163,310 | ) | ||||
Add: | |||||||||||||||
Impact of Selected Items: | |||||||||||||||
(Gain) Loss on the Mark-to-Market of Derivative Instruments | 16,058,370 | 5,645,586 | (15,170,174 | ) | 58,135,302 | ||||||||||
Write-off of Debt Issuance Costs | — | — | 95,135 | 1,089,507 | |||||||||||
Impairment of Oil and Natural Gas Properties | — | 43,820,791 | — | 237,012,834 | |||||||||||
Legal Settlements | 3,589,431 | — | 3,589,431 | — | |||||||||||
Selected Items, Before Income Taxes | 19,647,801 | 49,466,377 | (11,485,608 | ) | 296,237,643 | ||||||||||
Income Tax of Selected Items(1) | (1,316,686 | ) | (1,494,741 | ) | (1,222,555 | ) | (5,572,304 | ) | |||||||
Selected Items, Net of Income Taxes | 18,331,115 | 47,971,636 | (12,708,163 | ) | 290,665,339 | ||||||||||
Adjusted Net Income | $ | 2,243,648 | $ | 2,352,741 | $ | 1,946,754 | $ | 9,502,029 | |||||||
Weighted Average Shares Outstanding – Basic | 61,843,377 | 61,237,627 | 61,645,920 | 61,127,577 | |||||||||||
Weighted Average Shares Outstanding – Diluted | 62,114,238 | 61,771,363 | 61,991,292 | 61,825,191 | |||||||||||
Net Income (Loss) Per Common Share – Basic | $ | (0.26 | ) | $ | (0.74 | ) | $ | 0.24 | $ | (4.60 | ) | ||||
Add: | |||||||||||||||
Impact of Selected Items, Net of Income Taxes | 0.30 | 0.78 | (0.21 | ) | 4.76 | ||||||||||
Adjusted Net Income Per Common Share – Basic | $ | 0.04 | $ | 0.04 | $ | 0.03 | $ | 0.16 | |||||||
Net Income (Loss) Per Common Share – Diluted | $ | (0.26 | ) | $ | (0.74 | ) | $ | 0.24 | $ | (4.55 | ) | ||||
Add: | |||||||||||||||
Impact of Selected Items, Net of Income Taxes | 0.30 | 0.78 | (0.21 | ) | 4.70 | ||||||||||
Adjusted Net Income Per Common Share – Diluted | $ | 0.04 | $ | 0.04 | $ | 0.03 | $ | 0.15 | |||||||
______________
(1) | For the 2017 columns, this represents a tax impact using an estimated tax rate of 37.0% and 38.6% for the three and nine months ended September 30, 2017, respectively, which includes a reduction of $6.0 million and an increase of $5.7 million in our valuation allowance for the three and nine months ended September 30, 2017, respectively. 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. |
Reconciliation of Adjusted EBITDA
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Net Income (Loss) | $ | (16,087,467 | ) | $ | (45,618,895 | ) | $ | 14,654,917 | $ | (281,163,310 | ) | ||||
Add: | |||||||||||||||
Interest Expense | 16,672,632 | 16,145,440 | 49,404,601 | 48,290,447 | |||||||||||
Income Tax Benefit | — | — | — | — | |||||||||||
Depreciation, Depletion, Amortization and Accretion | 15,357,685 | 13,698,020 | 41,868,280 | 47,720,972 | |||||||||||
Impairment of Oil and Natural Gas Properties | — | 43,820,791 | — | 237,012,834 | |||||||||||
Non-Cash Share Based Compensation | 3,732,509 | (712,677 | ) | 5,265,868 | 2,308,793 | ||||||||||
Write-off of Debt Issuance Costs | — | — | 95,135 | 1,089,507 | |||||||||||
(Gain) Loss on the Mark-to-Market of Derivative Instruments | 16,058,370 | 5,645,586 | (15,170,174 | ) | 58,135,302 | ||||||||||
Adjusted EBITDA | $ | 35,733,729 | $ | 32,978,265 | $ | 96,118,627 | $ | 113,394,545 | |||||||