Northern Oil and Gas, Inc.
NORTHERN OIL & GAS, INC. (Form: 8-K, Received: 11/08/2017 16:38:06)


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 8-K
 

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): November 8, 2017
 

NORTHERN OIL AND GAS, INC.
(Exact name of Registrant as specified in its charter)
Minnesota
001-33999
95-3848122
(State or other jurisdiction
of incorporation)
(Commission File Number)
(IRS Employer
Identification No.)

601 Carlson Parkway, Suite 990  
Minnetonka, Minnesota
55305
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code   ( 952) 476-9800
 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions ( see General Instruction A.2. below):
o
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17CFR 240.14a-12)
o
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17CFR §240.12b-2).
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨





Item 2.02.      Results of Operations and Financial Condition .

On November 8, 2017, Northern Oil and Gas, Inc. issued a press release announcing 2017 third quarter financial and operating results. A copy of the press release is furnished as Exhibit 99.1 hereto.


Item 9.01.      Financial Statements and Exhibits .

Exhibit Number
 
Description
  
  
  
  
Press release of Northern Oil and Gas, Inc., dated November 8, 2017.







SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: November 8, 2017
NORTHERN OIL AND GAS, INC.
By /s/ Erik J. Romslo                                  
Erik J. Romslo
Executive Vice President, General Counsel and Secretary








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