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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2016
 
 
Commission File Number:  001-35371
 
Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter)
 
Delaware
 
61-1630631
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)

410 17th Street, Suite 1400
 
 
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)
(720) 440-6100
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x  Yes ¨  No
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x  Yes ¨  No
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer x
 
Accelerated filer ¨
 
 
 
Non-accelerated filer ¨
 
Smaller reporting company ¨
(Do not check if a smaller reporting company)
 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨  Yes x  No
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. As of November 7, 2016, the registrant had 49,672,252 shares of common stock outstanding.
 

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BONANZA CREEK ENERGY, INC.
INDEX
 
 
    
    
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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PART I - FINANCIAL INFORMATION
Item 1.     Financial Statements.
 
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
September 30, 2016
 
December 31, 2015
 
(in thousands, except share data)
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
133,430

 
$
21,341

Accounts receivable:
 

 
 

Oil and gas sales
22,167

 
25,322

Joint interest and other
4,937

 
31,224

Prepaid expenses and other
5,125

 
4,078

Inventory of oilfield equipment
8,994

 
8,543

Derivative asset
2,093

 
29,566

Total current assets
176,746

 
120,074

Property and equipment (successful efforts method), at cost:
 

 
 

Proved properties
2,519,695

 
1,618,970

Less: accumulated depreciation, depletion and amortization
(1,669,662
)
 
(943,081
)
Total proved properties, net
850,033

 
675,889

Unproved properties
162,334

 
185,530

Wells in progress
20,133

 
51,196

Oil and gas properties and natural gas plant held for sale, net of accumulated depreciation, depletion and amortization of $636,917 in 2015 (note 3)

 
214,922

Other property and equipment, net of accumulated depreciation of $10,983 in 2016 and $9,407 in 2015
6,789

 
9,729

Total property and equipment, net
1,039,289

 
1,137,266

Other noncurrent assets
8,362

 
2,301

Total assets
$
1,224,397

 
$
1,259,641

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued expenses (note 4)
$
55,930

 
$
96,360

Oil and gas revenue distribution payable
23,197

 
27,613

Revolving credit facility - current portion (note 5)
229,333

 

Contractual obligation for land acquisition

 
12,000

Senior Notes - current portion (note 5)
793,410

 

Total current liabilities
1,101,870

 
135,973

Long-term liabilities:
 

 
 

Long-term debt (note 5)

 
871,666

Ad valorem taxes
10,614

 
17,069

Asset retirement obligations
27,157

 
14,935

Asset retirement obligations for assets held for sale

 
10,591

Total liabilities
1,139,641

 
1,050,234

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 

 
 

Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding

 

Common stock, $.001 par value, 225,000,000 shares authorized, 49,690,054 and 49,754,408 issued and outstanding in 2016 and 2015, respectively
49

 
49

Additional paid-in capital
813,351

 
806,386

Retained deficit
(728,644
)
 
(597,028
)
Total stockholders’ equity
84,756

 
209,407

Total liabilities and stockholders’ equity
$
1,224,397

 
$
1,259,641


The accompanying notes are an integral part of these condensed consolidated financial statements.

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME(UNAUDITED)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands, except per share amounts)
Operating net revenues:
 

 
 

 
 

 
 

Oil and gas sales
$
49,325

 
$
72,149

 
$
148,029

 
$
235,647

Operating expenses:
 

 
 

 
 

 
 

Lease operating expense
9,893

 
17,155

 
33,928

 
51,710

Gas plant and midstream operating expense
2,874

 
3,081

 
10,198

 
8,685

Severance and ad valorem taxes
4,100

 
2,411

 
11,531

 
13,055

Exploration

 
6,979

 
943

 
13,225

Depreciation, depletion and amortization
27,296

 
58,635

 
84,602

 
187,564

Impairment of oil and gas properties

 
166,780


10,000

 
166,780

Abandonment and impairment of unproved properties
7,682

 
1,630

 
24,463

 
21,627

Unused commitments
1,688

 

 
3,460

 

General and administrative (including $1,863, $3,164, $7,249 and $10,951, respectively, of stock-based compensation)
18,671

 
17,818

 
49,591

 
56,292

Total operating expenses
72,204

 
274,489

 
228,716

 
518,938

Loss from operations
(22,879
)
 
(202,340
)
 
(80,687
)
 
(283,291
)
Other income (expense):
 

 
 

 
 

 
 

Derivative gain (loss)
2,206

 
37,894

 
(11,724
)
 
51,272

Interest expense
(15,142
)
 
(14,073
)
 
(46,216
)
 
(42,779
)
Gain on termination fee (note 3)

 

 
6,000

 

Other income (loss)
913

 
(2,077
)
 
1,011

 
(1,929
)
Total other income (expense)
(12,023
)
 
21,744

 
(50,929
)
 
6,564

Loss from operations before taxes
(34,902
)
 
(180,596
)
 
(131,616
)
 
(276,727
)
Income tax benefit

 
68,297

 

 
104,843

Net loss
$
(34,902
)
 
$
(112,299
)
 
$
(131,616
)
 
$
(171,884
)
Comprehensive loss
$
(34,902
)
 
$
(112,299
)
 
$
(131,616
)
 
$
(171,884
)
 
 
 
 
 
 
 
 
Basic and diluted net loss per common share
$
(0.71
)
 
$
(2.25
)
 
$
(2.67
)
 
$
(3.56
)
 
 
 
 
 
 
 
 
Basic and diluted weighted-average common shares outstanding
49,324

 
48,962

 
49,244

 
47,485

The accompanying notes are an integral part of these condensed consolidated financial statements.


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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
Nine Months Ended September 30,
 
2016
 
2015
 
(in thousands)
Cash flows from operating activities:
 

 
 

Net loss
$
(131,616
)
 
$
(171,884
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
84,602

 
187,564

Deferred income tax benefit

 
(105,595
)
Impairment of oil and gas properties
10,000


166,780

Abandonment and impairment of unproved properties
24,463

 
21,627

Dry hole expense
905

 
7,628

Stock-based compensation
7,249

 
10,951

Amortization of deferred financing costs and debt premium
2,705

 
1,692

Accretion of contractual obligation for land acquisition

 
814

Derivative (gain) loss
11,724

 
(51,272
)
Derivative cash settlements
15,749

 
88,372

Other
127

 
283

Changes in current assets and liabilities:
 
 
 

Accounts receivable
29,442

 
28,253

Prepaid expenses and other assets
(1,047
)
 
994

Accounts payable and accrued liabilities
(23,252
)
 
(11,905
)
Settlement of asset retirement obligations
(473
)
 
(778
)
Net cash provided by operating activities
30,578

 
173,524

Cash flows from investing activities:
 

 
 

Acquisition of oil and gas properties
(919
)
 
(13,602
)
Payments of contractual obligation
(12,000
)

(12,000
)
Exploration and development of oil and gas properties
(47,491
)
 
(361,131
)
(Increase) decrease in restricted cash
(7,707
)
 
2,926

Additions to property and equipment - non oil and gas
(106
)
 
(2,390
)
Net cash used in investing activities
(68,223
)
 
(386,197
)
Cash flows from financing activities:
 

 
 

Proceeds from credit facility
209,000

 
115,000

Payments to credit facility
(58,667
)
 
(79,000
)
Proceeds from sale of common stock

 
209,300

Offering costs related to sale of common stock

 
(6,620
)
Offering costs related to sale of Senior Notes

 
(99
)
Payment of employee tax withholdings in exchange for the return of common stock
(283
)
 
(2,593
)
Deferred financing costs
(316
)
 
(573
)
Net cash provided by financing activities
149,734

 
235,415

Net change in cash and cash equivalents
112,089

 
22,742

Cash and cash equivalents:
 

 
 

Beginning of period
21,341

 
2,584

End of period
$
133,430

 
$
25,326

Supplemental cash flow disclosure:
 

 
 

Cash paid for interest
$
39,235

 
$
36,759

Stock issued for litigation settlement
$

 
$
326

Cash paid for income taxes
$

 
$
820

Changes in working capital related to drilling expenditures
$
(27,952
)
 
$
(9,441
)
The accompanying notes are an integral part of these condensed consolidated financial statements.

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
 
NOTE 1 - ORGANIZATION AND BUSINESS
 
Bonanza Creek Energy, Inc. (“BCEI” or, together with its consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. The Company's oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado and in the Dorcheat Macedonia Field in southern Arkansas.
 
NOTE 2 - BASIS OF PRESENTATION
 
These statements have been prepared in accordance with the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information with the condensed consolidated balance sheets (“balance sheets”) as of December 31, 2015, being derived from audited financial statements. The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles for complete financial statements. There has been no material change in the information disclosed in the notes to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 (the “2015 Form 10-K”), except as disclosed herein. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the quarter are not necessarily indicative of the results to be expected for the full fiscal year. The Company evaluated events subsequent to the balance sheet date of September 30, 2016, and through the filing date of this report. Certain prior period amounts are reclassified to conform to the current period presentation, when necessary.
 
Principles of Consolidation
 
The balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes Eastern Company, LLC and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated.

Significant Accounting Policies
 
The significant accounting policies followed by the Company were set forth in Note 1 to the 2015 Form 10-K and are supplemented by the notes throughout this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2015 Form 10-K.

Going Concern Uncertainty

Since the first quarter of 2016, the Company’s liquidity outlook has deteriorated due to the Company's inability to sell assets given current market conditions and counterparty concerns about the Company's liquidity and current capital structure, borrowing base reductions that have occurred during 2016, continuation of depressed commodity prices and the inability to access the debt and capital markets. In addition, the Company’s senior secured revolving credit agreement (the “revolving credit facility”) is subject to scheduled redeterminations of its borrowing base, semi-annually, as early as April and October of each year, based primarily on reserve report values using lender commodity price expectations at such time as well as other factors within the discretion of the lenders that are party to the revolving credit facility.

As a result of these and other factors, the following issues have adversely impacted the Company’s ability to continue as a going concern:
the Company’s ability to comply with financial covenants and ratios in its revolving credit facility and indentures has been affected by continued low commodity prices. Among other things, the Company is required under its revolving credit facility to maintain a minimum interest coverage ratio (the “minimum interest coverage ratio”) that must exceed 2.50 to 1.00. Absent a waiver, amendment or forbearance agreement, failure to meet these covenants and ratios would result in an Event of Default (as defined in the revolving credit agreement) and, to the extent the applicable lenders so elect, an acceleration of the Company’s existing

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indebtedness, causing such debt of $229.3 million, as of September 30, 2016, to be immediately due and payable. Based on the Company's financial results through the third quarter of 2016, it is no longer in compliance with its minimum interest coverage ratio requirement. The minimum interest coverage ratio is calculated by dividing trailing twelve-month EBITDAX by trailing twelve-month interest expense. If a waiver, amendment or forbearance agreement is not obtained, the applicable credit facility lenders could give notice of acceleration as a result of this non-compliance. The Company does not currently have adequate liquidity to repay all of its outstanding debt in full if such debt were accelerated;
because the revolving credit facility borrowing base was redetermined in May 2016 to $200.0 million, the Company was overdrawn by $88.0 million and has been making mandatory monthly repayments of approximately $14.7 million. The borrowing base was further reduced on October 31, 2016 to $150.0 million, which is less than the current amount drawn. Under the terms of the credit agreement, the Company has a 20-day period from the date of redetermination to inform the bank group of its intended method to cure its deficiency. Please refer to Note 5 - Long-Term Debt for additional discussion on the Company's available options to cure its borrowing base deficiency. Depending on its election to cure the deficiency, the Company may not have sufficient cash on hand to be able to make the mandatory repayments associated with curing the deficiency at the time they are due;
the Company’s ability to make interest payments as they become due and repay indebtedness upon maturities (whether under existing terms or as a result of acceleration) is impacted by the Company’s liquidity. As of September 30, 2016, the Company had a $29.3 million borrowing base deficiency under its revolving credit facility and $133.4 million in cash and cash equivalents. As a result of the October 31, 2016 redetermination, the Company's borrowing base deficiency is $64.7 million, as of the date of filing;
the Company has two purchase and transportation agreements to deliver fixed determinable quantities of crude oil. The first agreement went into effect during the second quarter of 2015 for 12,580 barrels per day over an initial five year term. Based on current production estimates, assuming no future drilling and completion activity, the Company anticipates shortfalls in delivering the minimum volume commitments throughout the remainder of 2016. The Company has incurred $1.5 million in minimum volume commitment deficiency payments as of September 30, 2016. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $1.7 million for the remainder of 2016 and an aggregate $44.8 million in deficiency payments for 2017 through April 2020, when the agreement expires. In accordance with an adequate assurance of performance provision contained in the contract, the counterparty withheld $5.0 million from the Company's revenue payment during the third quarter of 2016. This payment is being held in a segregated account and is reflected in the other noncurrent assets line item in the accompanying balance sheets. The second agreement became effective on November 1, 2016 for 15,000 barrels per day over an initial seven year term. Based on current production estimates, assuming no future drilling and completion activity, and not designating any barrels to this commitment until May 2020. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $4.8 million in 2016 and an aggregate $165.2 million in deficiency payments for 2017 through October 2023, when the agreement expires. The actual amount of deficiency payments could vary on both contracts depending on the outcome of the Company's ability to renegotiate and execute on one or more of its current liquidity strategies; and
if the Company is unable to obtain a waiver from or otherwise reach an agreement with the lenders under the revolving credit facility and the indebtedness under the revolving credit facility is accelerated, then an Event of Default (as defined in the underlying indentures) under the Company's 6.75% Senior Notes due 2021 (“6.75% Senior Notes”) and 5.75% Senior Notes due 2023 (“5.75% Senior Notes”, collectively referred to as the “Senior Notes”) would occur. If an Event of Default occurs, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes, may declare the entire principal under the Senior Notes to be due and payable immediately. The Company made the October 15, 2016 interest payment of $17.0 million, which included per diem default interest, on its 6.75% Senior Notes to the indenture trustee within the 30-day grace period allowed under the governing indenture. The revolving credit facility and Senior Notes have cross default clauses.

If lenders, and subsequently noteholders, accelerate the Company’s outstanding indebtedness ($1.0 billion as of September 30, 2016), it will become immediately due and payable. In the event of acceleration, the Company does not have sufficient liquidity to repay those amounts and would have to seek relief through a Chapter 11 Bankruptcy proceeding. Due to

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covenant violations, the Company classified the revolving credit facility and Senior Notes as current liabilities as of September 30, 2016.

The significant risks and uncertainties described above raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. The Company is currently in discussions with various stakeholders, regarding a potential (i) debt for equity exchange or (ii) private secured financing transaction. The Company is also seeking to obtain waivers or amendments from its lenders. There can be no assurance that sufficient liquidity can be obtained from one or more of these actions or that these actions can be consummated within the period needed.

See Note 5 - Long-Term Debt and Note 6 - Commitment and Contingencies for additional details about the Company’s debt and commitments.

Recently Issued Accounting Standards
On January 1, 2016, the Company adopted FASB Update No. 2015 -03 - Interest - Imputation of Interest - Simplifying the Presentation of Debt Issuance Costs and Update No. 2015-15, Interest - Imputation of Interest - Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements on a retrospective basis. These updates require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The adoption resulted in a reclassification that reduced other noncurrent assets and senior notes - current portion by $12.1 million as of September 30, 2016 and reduced other noncurrent assets and long-term debt by $13.7 million on the accompanying balance sheets as of December 31, 2015.
In January 2016, the FASB issued Update No. 2016-01 – Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

In February 2016, the FASB issued Update No. 2016-02 – Leases to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This authoritative guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

In March 2016, the FASB issued Update No. 2016-08 – Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which clarifies the implementation guidance on principal versus agent considerations. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. The Company has started reviewing its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company's financial statements or disclosures.

In March 2016, the FASB issued Update No. 2016-09 – Compensation - Stock Compensation. The update simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This authoritative guidance is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

In April 2016, the FASB issued Update No. 2016-10 – Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing, which clarifies identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those two areas. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. The Company has started reviewing its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company's financial statements or disclosures.

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In May 2016, the FASB issued Update No. 2016-12 – Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients, which identifies certain areas for improvement within Topic 606, which specifies the accounting for revenue from contracts with customers. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. The Company has started reviewing its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company's financial statements or disclosures.

In August 2016, the FASB issued Update No. 2016-15 – Classification of Certain Cash Receipts and Cash Payments, which clarifies the presentation of specific cash receipts and cash payments within the statement of cash flows. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

NOTE 3 - ASSETS HELD FOR SALE

Previously, the Company had assets held for sale which consisted of the Company’s ownership interests in Rocky Mountain Infrastructure, LLC (“RMI”) and all assets within the Company's Mid-Continent region. During the second quarter, these assets were placed back in to assets held for use in the proved properties, unproved properties and wells in progress financial statement line items in the accompanying balance sheets, including the corresponding asset retirement obligation liability. During the second quarter of 2016, the Company recorded $3.0 million of catch-up depreciation on the RMI assets for the nine months that the assets were classified as held for sale and recorded a $6.0 million gain on termination fee shown in the accompanying statements of operations for the nine months ended September 30, 2016. The fair value of the Mid-Continent region was lower than the carrying value of the assets prior to classification as held for sale less any depletion that would have been recognized had the assets continuously been held and used, and therefore, no catch-up depletion was recorded for those assets.

The Company worked diligently to sell the asset packages listed above, but ultimately determined that current market conditions and liquidity concerns related to the Company's current balance sheet did not support the successful sale of such assets. Further, the Company's collateral value under the revolving credit facility would have been negatively impacted by the Mid-Continent region assets sale, thus negating any cash gained from such sale.

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
 
Accounts payable and accrued expenses contain the following:
 
As of September 30,
 
As of December 31,
 
2016
 
2015
 
(in thousands)
Drilling and completion costs
$
4,507

 
$
32,459

Accounts payable trade
985

 
1,085

Accrued general and administrative cost
6,091

 
10,643

Lease operating expense
3,313

 
4,731

Accrued reclamation cost

 
162

Accrued interest
18,508

 
14,231

Production and ad valorem taxes and other
22,526

 
33,049

Total accounts payable and accrued expenses
$
55,930

 
$
96,360



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NOTE 5 - LONG-TERM DEBT
 
Long-term debt consisted of the following:
 
As of September 30,
 
As of December 31,
 
2016
 
2015
 
(in thousands)
Revolving credit facility
$
229,333

 
$
79,000

6.75% Senior Notes due 2021
500,000

 
500,000

Unamortized premium on 6.75% Senior Notes
5,472

 
6,392

5.75% Senior Notes due 2023
300,000

 
300,000

Less debt issuance costs - Senior Notes
(12,062
)
 
(13,726
)
Total debt, net
1,022,743

 
871,666

Less current portion(1)
(1,022,743
)
 

Total long-term debt
$

 
$
871,666

______________________
(1)
Due to covenant violations and potential related cross default clauses, the Company classified the revolving credit facility and Senior Notes as current liabilities as of September 30, 2016. Please refer to the Going Concern Uncertainty section in Note 2 - Basis of Presentation for additional discussion.

Credit Facility
 
The borrowing base under the Company’s senior secured revolving Credit Agreement, dated March 29, 2011, was reduced on May 20, 2016 from $475.0 million to $200.0 million, and was further reduced from $200.0 million to $150.0 million on October 31, 2016. The total credit facility size of $1.0 billion remaining unchanged. The borrowing base is redetermined semiannually, as early as April and October of each year. The revolving credit facility is collateralized by substantially all of the Company’s assets and matures on September 15, 2017. As of September 30, 2016, the Company had $229.3 million outstanding under the revolving credit facility and had a borrowing base deficiency of $29.3 million to be paid back in two remaining monthly installments of $14.7 million, with no additional available borrowing capacity. As of the date of filing, the Company had $214.7 million outstanding under the revolving credit facility and a total borrowing base deficiency, including the deficiency from the October 31, 2016 redetermination, of $64.7 million. The Company has one remaining monthly installment of $14.7 million to cure its May 2016 redetermination borrowing base deficiency. The remaining $50.0 million deficiency resulting from the October 31, 2016 redetermination is intended to be cured in a method elected by the Company as set forth in the credit agreement. Under the terms of the credit agreement, the Company has a 20-day period from the date of the deficiency notice to inform the bank group of its intended method to cure the deficiency. The Company's options to cure this deficiency are consistent with those available at the time of the May 20, 2016 redetermination, and include: (a) repaying the deficiency amount within 30 days from the deficiency notice date; (b) pledge, within 30 days after the deficiency notice date, additional oil and gas properties acceptable to the lenders, which the lenders deem sufficient in their sole discretion to eliminate the borrowing base deficiency; (c) repay the deficiency amount in six monthly installments equal to one-sixth of the borrowing base deficiency; (d) cure the deficiency through a combination of options (b) and (c) above. As of the date of filing, the Company had not informed the bank group of its intended method to cure its borrowing base deficiency.
 
The revolving credit facility restricts, among other items, certain dividend payments, additional indebtedness, asset sales, loans, investments and mergers. The revolving credit facility also contains certain financial covenants, which require the maintenance of certain financial and leverage ratios, as defined by the revolving credit facility. The revolving credit facility contains a ratio of maximum senior secured debt to trailing twelve-month EBITDAX (defined as earnings before interest expense, income tax expense, depreciation, depletion and amortization expense, and exploration expense and other non-cash charges) that must not exceed 2.50 to 1.00 and a minimum interest coverage ratio that must exceed 2.50 to 1.00. The maximum senior secured debt ratio is calculated by dividing borrowings under the revolving credit facility, balances drawn under letters of credit, and any outstanding second lien debt divided by trailing twelve-month EBITDAX. The minimum interest coverage ratio is calculated by dividing trailing twelve-month EBITDAX by trailing twelve-month interest expense. The revolving credit facility also contains a minimum current ratio covenant of 1.00 to 1.00. The revolving credit facility agreement states that the current ratio is to exclude the current portion of long-term debt, as such the classification of the Company's long-term debt to current liabilities did not impact the current ratio. Based on the financial results through the third quarter of 2016, the Company

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is no longer in compliance with its minimum interest coverage ratio requirement. If a waiver, amendment or forbearance agreement is not obtained, the applicable lenders could give notice of acceleration as a result of this non-compliance.
 
Senior Unsecured Notes
 
The $500.0 million aggregate principal amount of 6.75% Senior Notes that mature on April 15, 2021 and the $300.0 million aggregate principal amount of 5.75% Senior Notes that mature on February 1, 2023 are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and future unsecured senior debt, and are senior in right of payment to any future subordinated debt. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Company's existing and future domestic subsidiaries that guarantee or are borrowers under its revolving credit facility. The Company is subject to certain covenants under the respective indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including certain dividends.
 
NOTE 6 - COMMITMENTS AND CONTINGENCIES

Legal Proceedings 

From time to time, the Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its condensed consolidated financial statements. In accordance with accounting authoritative guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations. As of the filing date of this report, there were no material pending or overtly threatened legal actions against the Company of which it is aware.

Commitments

As previously disclosed in the 2015 Form 10-K, the Company has two purchase and transportation agreements to deliver fixed determinable quantities of crude oil. The first agreement went into effect during the second quarter of 2015 for 12,580 barrels per day over an initial five year term. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $1.7 million for the remainder of 2016 and an aggregate $44.8 million in deficiency payments for 2017 through April 2020, when the agreement expires. The future anticipated shortfall assumes current production forecasts that contemplate no future drilling and completion activity. The Company has incurred $1.5 million as of September 30, 2016 in deficiency payments on the minimum volume commitments.

The second agreement became effective on November 1, 2016 for 15,000 barrels per day over an initial seven year term. Based on current production volumes with no future drilling activity, and the Company not designating any barrels to this commitment until May 2020, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $4.8 million in 2016 and an aggregate $165.2 million in deficiency payments for 2017 through October 2023, when the agreement expires.

The actual amount of deficiency payments could vary depending on the outcome of the Company's ability to execute on its current liquidity strategies and future drilling. Due to continued low commodity prices, the suspension of drilling and completion activity, the Company intends to aggressively pursue restructuring the terms of these contracts, which could include among other items, altering the differential pricing and or committed volumes, and the associated deficiency fees for not meeting minimum volume commitments.

On July 31, 2012, the Company acquired leases to approximately 5,600 net acres in the Wattenberg Field from the State of Colorado, State Board of Land Commissioners. The Company paid approximately $12.0 million at closing and $12.0

11

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million each subsequent year thereafter. During the second quarter of 2016, the Company made the final $12.0 million payment, which caused release of the $12.0 million letter of credit securing future payments.

There have been no other material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in the 2015 Form 10-K.

NOTE 7 - STOCK-BASED COMPENSATION
 
Restricted Stock under the Long Term Incentive Plan
 
The Company grants shares of restricted stock to directors, eligible employees and officers under its Long Term Incentive Plan, as amended and restated (“LTIP”). Each share of restricted stock represents one share of the Company’s common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. Each share of restricted stock is entitled to a non-forfeitable dividend, if the Company were to declare one, and has the same voting rights as a share of the Company’s common stock. Shares of restricted stock are valued at the closing price of the Company’s common stock on the grant date and are recognized as general and administrative expense over the vesting period of the award.
 
Total expense recorded for restricted stock for the three month periods ended September 30, 2016 and 2015 was $1.2 million and $2.5 million, respectively, and $5.3 million and $9.0 million for the nine months ended September 30, 2016 and 2015, respectively. As of September 30, 2016, unrecognized compensation cost was $5.5 million and will be amortized through 2018.
 
A summary of the status and activity of non-vested restricted stock for the nine months ended September 30, 2016 is presented below.
 
Restricted
Stock
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year
731,818

 
$
29.47

Granted
113,044

 
$
0.98

Vested
(343,349
)
 
$
31.14

Forfeited
(95,899
)
 
$
25.86

Non-vested at end of quarter
405,614

 
$
21.11

 
Performance Stock Units under the Long Term Incentive Plan
 
The Company grants performance stock units (“PSUs”) to certain officers under its LTIP. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. PSUs are determined at the end of each annual measurement period over the course of the three-year performance cycle in an amount up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number of PSUs may be earned during the performance cycle) although no stock is actually awarded to the participant until the end of the entire three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The performance criterion for the PSUs is based on a comparison of the Company’s total shareholder return (“TSR”) for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. The TSR for the Company and each of the peer companies is determined by dividing (A)(i) the average share price for the last 30 trading days of the applicable measuring period, minus (ii) the average share price for the 30 trading days immediately preceding the beginning of the applicable measuring period, by (B) the average share price for the 30 trading days immediately preceding the beginning of the applicable measuring period. The number of earned shares of the Company's common stock will be calculated based on which quartile its TSR percentage ranks as of the end of the annual measurement period relative to the other companies in the comparator group. The fair value of each PSU is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of PSUs to be earned during the performance period. Compensation expense associated with PSUs is recognized as general and administrative expense over the measurement period.
 

12


Total expense recorded for PSUs for the three month period ended September 30, 2016 and 2015 was $0.3 million and $0.6 million, respectively, and $1.5 million and $2.0 million for the nine months ended September 30, 2016 and 2015, respectively. As of September 30, 2016, there was $1.9 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2018.
 
A summary of the status and activity of PSUs for the nine months ended September 30, 2016 is presented below:

 
PSU
 
Weighted-Average
Grant-Date
Fair Value
Non-vested at beginning of year (1)
114,833

 
$
35.27

Granted(1)

 
$

Vested(1)

 
$

Forfeited(1)
(25,780
)
 
$
35.34

Non-vested at end of quarter(1)
89,053

 
$
35.36

____________________________
(1)
The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.

Long Term Incentive Plan Units

During the third quarter, the Company granted 2,808,558 of LTIP units (“units”) for a total fair value $2.7 million, that will settle in shares of the Company's common stock upon vesting. The units vest in one-third increments over three years. The units contain a share price cap of $26 that incrementally decreases the number of shares of the Company's common stock that will be released upon vesting if the Company's common stock were to exceed the share price cap.

Total expense recorded for the units for the three and nine month periods ended September 30, 2016 was $0.4 million. As of September 30, 2016, there was $2.0 million of total unrecognized compensation expense related to unvested units to be amortized through 2019.

A summary of the status and activity of non-vested units for the nine months ended September 30, 2016 is presented below.
 
LTIP Units
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year

 
$

Granted
2,808,558

 
$
0.98

Vested

 
$

Forfeited
(318,663
)
 
$
0.98

Non-vested at end of quarter
2,489,895

 
$
0.98


NOTE 8 - FAIR VALUE MEASUREMENTS
 
The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:


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Level 1: Quoted prices are available in active markets for identical assets or liabilities
 
Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

Level 3: Significant inputs to the valuation model are unobservable
 
Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
 
The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of September 30, 2016 and December 31, 2015 and their classification within the fair value hierarchy:
 
As of September 30, 2016
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Derivative assets(1)
$

 
$
2,093

 
$

Unproved properties(2)
$

 
$

 
$
162,202

 
 
 
As of December 31, 2015
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Derivative assets(1)
$

 
$
29,566

 
$

Proved properties(2)
$

 
$

 
$
811,913

Unproved properties(2)
$

 
$

 
$
185,530

Asset retirement obligations(3)
$

 
$

 
$
2,027

____________________________
(1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.
(2)
This represents non-financial assets that are measured at fair value on a nonrecurring basis due to impairments. This is the fair value of the asset base that was subjected to impairment and may not reflect the entire asset balance as presented on the accompanying balance sheets. Please refer to the Proved Oil and Gas Properties and Unproved Oil and Gas Properties sections below for additional discussion.
(3)
This represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.
 
Derivatives
 
Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. Presently, all of the Company's derivative arrangements are concentrated with three counterparties, all of which are lenders under the Company’s revolving credit facility.
 

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Proved Oil and Gas Properties
 
Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the NYMEX strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no impairments recorded during the second or third quarters of 2016. The Company impaired the Mid-Continent region which had a carrying value of $110.0 million to its estimated fair value, based on the most recent bid the Company received, at the time it was held for sale of $100.0 million and recognized an impairment of $10.0 million during the first quarter of 2016. The Company impaired the Mid-Continent region, which had a carrying value of $431.2 million, to its fair value of $110.0 million and recognized an impairment of $321.2 million for the year ended December 31, 2015. The Company impaired the Rocky Mountain region, which had a carrying value of $1.1 billion, to its fair value of $701.9 million and recognized an impairment of $419.3 million for the year ended December 31, 2015.
 
Unproved Oil and Gas Properties
 
Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be fully recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, remaining lease life and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. Due to leases expiring, the Company impaired non-core acreage in the Wattenberg Field, which had a carrying value of $186.7 million, to its fair value of $162.2 million and recognized an impairment of unproved properties of $24.5 million for the nine months ended September 30, 2016. Due to leases expiring, the Company impaired non-core acreage in the Wattenberg Field, which had a carrying value of $210.3 million, to its fair value of $185.5 million and recognized an impairment of unproved properties for the year ended December 31, 2015 of $24.8 million. The Company also fully impaired the North Park Basin in 2015, due to a change in the Company’s development plan, recognizing an impairment of unproved properties of $8.7 million.
 
Asset Retirement Obligation
 
The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value as of September 30, 2016. The Company had $2.0 million of asset retirement obligations recorded at fair value as of December 31, 2015.
 
Long-term Debt


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As of September 30, 2016, the Company had $500.0 million of outstanding 6.75% Senior Notes and $300.0 million of outstanding 5.75% Senior Notes, all of which are unsecured senior obligations. The 6.75% Senior Notes are recorded at cost, plus the unamortized premium and net deferred financing costs, on the accompanying balance sheets at $498.3 million and $498.1 million as of September 30, 2016 and December 31, 2015, respectively. The fair value of the 6.75% Senior Notes as of September 30, 2016 and December 31, 2015 was $233.8 million and $301.3 million, respectively. The 5.75% Senior Notes are recorded at cost, net of deferred financing costs, on the accompanying balance sheets at $295.1 million and $294.5 million as of September 30, 2016 and December 31, 2015, respectively. The fair value of the 5.75% Senior Notes as of September 30, 2016 and December 31, 2015 was $138.6 million and $163.1 million, respectively. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price. The Company’s revolving credit facility approximates fair value as the applicable interest rates are variable. The outstanding balance under the revolving credit facility as of September 30, 2016 and December 31, 2015 was $229.3 million and $79.0 million, respectively.
 
NOTE 9 - DERIVATIVES
 
The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. The Company’s derivatives include oil swap arrangements and puts, none of which qualify as having hedging relationships for accounting purposes. During the first quarter of 2016, the Company converted its three-way collars into fixed price swaps and puts.
 
As of September 30, 2016, and as of the filing date of this report, the Company had the following derivative commodity contracts in place:
Settlement
Period
 
Derivative
Instrument
 
Total Volumes
(Bbls per day)
 
Average
Fixed
Price
 
Fair Market
Value of Assets
 
 
 
 
 
 
 
 
(in thousands)
Oil
 
 
 
 
 
 
 
 

4Q 2016
 
Swap
 
2,303
 
$52.83
 
814

4Q 2016
 
Put
 
4,031
 
$51.01
 
1,279

 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
$
2,093

 
Derivative Assets Fair Value
 
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets.
 
The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of September 30, 2016 and December 31, 2015:
 
 
 
As of September 30, 2016
 
As of December 31, 2015
 
Balance Sheet Location
 
Fair Value
 
Fair Value
 
 
 
(in thousands)
 
(in thousands)
Derivative Assets:
 
 
 
 
 

Commodity contracts
Current assets
 
$
2,093

 
$
29,566

Commodity contracts
Noncurrent assets
 

 

Derivative Liabilities:
 
 
 

 
 

Commodity contracts
Current liabilities
 

 

Commodity contracts
Long-term liabilities
 

 

Total derivative asset
 
 
$
2,093

 
$
29,566


The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations:

16

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Three months ended September 30,
 
Nine months ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
 
(in thousands)
Derivative cash settlement gain:
 

 
 

 
 

 
 

Oil contracts
$
4,348

 
$
37,027

 
$
15,749

 
$
86,325

Gas contracts

 
690

 

 
2,047

Total derivative cash settlement gain(1)
$
4,348

 
$
37,717

 
$
15,749

 
$
88,372

 
 
 
 
 
 
 
 
Change in fair value gain (loss)
$
(2,142
)
 
$
177

 
$
(27,473
)
 
$
(37,100
)
 
 
 
 
 
 
 
 
Total derivative gain (loss)(1)
$
2,206

 
$
37,894

 
$
(11,724
)
 
$
51,272

_______________________________
(1)
Total derivative gain (loss) and the derivative cash settlement gain for the nine months ended September 30, 2016 and 2015 is reported in the derivative (gain) loss and derivative cash settlements line items on the accompanying statements of cash flows within the net cash provided by operating activities.
 
NOTE 10  - EARNINGS PER SHARE
 
The Company issues shares of restricted stock entitling the holders to receive non-forfeitable dividends, if and when, the Company was to declare a dividend, before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two-class method. The two-class method allocates earnings for the period between common shareholders and participating shareholders and losses to common shareholders only.
 
The Company issues units, which represent the right to receive, upon vesting, shares of the Company's common stock on a one to one basis up to a share price of $26. In the event the price of the Company's common stock were to exceed $26, the number of shares distributed would be adjusted downward so that the shares distributed would represent a value equivalent to $26 per share.

The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company’s common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs and units is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the measurement period applicable to such PSUs and units. Please refer to Note 7- Stock-Based Compensation for additional discussion regarding these awards.

The following table sets forth the calculation of loss per basic and diluted shares for the three and nine month periods ended September 30, 2016 and 2015.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands, except per share amounts)
 
 

 
 

 
 

 
 

Net loss
$
(34,902
)
 
$
(112,299
)
 
$
(131,616
)
 
$
(171,884
)
Less: undistributed loss to unvested restricted stock

 

 

 

Undistributed loss to common shareholders
(34,902
)
 
(112,299
)
 
(131,616
)
 
(171,884
)
Basic net loss per common share
$
(0.71
)
 
$
(2.25
)
 
$
(2.67
)
 
$
(3.56
)
Diluted net loss per common share
$
(0.71
)
 
$
(2.25
)
 
$
(2.67
)
 
$
(3.56
)
 
 
 
 
 
 
 
 
Weighted-average shares outstanding - basic
49,324

 
48,962

 
49,244

 
47,485

Add: dilutive effect of contingent PSUs

 

 

 

Weighted-average shares outstanding - diluted
49,324

 
48,962

 
49,244

 
47,485


17

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The Company was in a net loss position for the three and nine months ended September 30, 2016 and 2015, which made any potentially dilutive shares anti-dilutive. There were 425,761 and 569,943 shares that were anti-dilutive for the three and nine months ended September 30, 2016. There were 156,750 and 265,280 shares that were anti-dilutive for the three and nine months ended September 30, 2015. The participating shareholders are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding common shareholders.

NOTE 11 - INCOME TAXES
 
The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. During the three and nine month periods ended September 30, 2016, the effective tax rate was 0.0%, respectively. During the three and nine month periods ended September 30, 2015, the effective tax rate was 37.8% and 37.9%, respectively. At December 31, 2015, a full valuation allowance was placed against the net deferred tax assets, which resulted in the Company’s current tax rate differing from the U.S. statutory income tax rate.    
As of September 30, 2016, the Company had no unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that should impact the Company's tax position taken thus far in 2016. Given the substantial net operating loss carry forward at the federal level, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated, and any such adjustments would likely only adjust the Company's net operating loss carry forward.
 
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2015, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
 
Executive Summary
 
We are a Denver-based energy company engaged in the acquisition, exploration, development, and production of onshore oil and associated liquids-rich natural gas in the United States. We went public in December of 2011 with our shares of common stock trading on the NYSE under the symbol “BCEI.”
 
Our operations are focused in the Wattenberg Field in Colorado and the Dorcheat Macedonia Field in southern Arkansas. The Wattenberg Field is one of the premier oil and gas resource plays in the United States benefiting from a low cost structure and strong production efficiencies, established reserves and prospective drilling opportunities, which allows for predictable production and reserve growth.

Given the deterioration in the Company's liquidity since the first quarter of 2016, there is now substantial doubt regarding the Company's ability to continue as a going concern. In response, the Company is addressing its current liquidity concerns with the assistance of advisors by pursuing the following potential strategies: (i) a debt for equity exchange or (ii) a private secured financing transaction. The Company is also seeking to obtain waivers or amendments from its lenders. Please refer to the Liquidity and Capital Resources section below for additional discussion. With the exception of one vertical well drilled during the third quarter, we ceased all drilling at the end of the first quarter of 2016 and reduced our future operating and corporate costs.

Senior Management Changes

Anthony Buchanon, Executive Vice President and Chief Operating Officer, has resigned from the Company effective August 2, 2016. In conjunction with Mr. Buchanon’s departure, Jeff Wojahn began serving as Senior Operations Advisor, in conjunction with his continued capacity as an independent non-executive director of the Company.
Additionally, effective October 28, 2016, Lynn E. Boone, the Company’s Senior Vice President, Reserves, departed from the Company.

18

Table of Contents

Effective October 1, 2016, the Company’s board of directors promoted Scott Fenoglio, previously the Company’s Vice President, Planning, to serve as the Company’s Senior Vice President, Finance and Planning and principal financial officer.
Effective October 17, 2016, the Company’s board of directors appointed Cyrus D. Marter IV to serve as the Company’s Senior Vice President, General Counsel and Secretary.
Financial and Operating Results
Our financial and operational results include:
Net loss of $34.9 million for the third quarter of 2016, as compared to a net loss of $112.3 million for the third quarter of 2015 due primarily to a decrease in impairments of oil and gas properties partially offset by a 2015 tax benefit; and
Decrease in sales volumes of 28% to 1,928.9 MBoe in the third quarter of 2016 from 2,663.5 MBoe in the third quarter of 2015, with oil production representing approximately 52% of total sales volumes in the third quarter of 2016.
 
Outlook for Fourth Quarter 2016
 
Beginning in 2014, the oil and natural gas industry began to experience a sharp decline in commodity prices. Caused in part by global supply and demand imbalances and an oversupply of oil in the United States, the pricing declines have extended into 2016 and the timing of any rebound is uncertain. Low commodity prices resulted in a reduction of our revenues, profitability, cash flows, proved reserve values and our stock price.

We estimate capital expenditures for the fourth quarter of 2016 to range from $6.0 million to $8.0 million. With the exception of one vertical well drilled during the third quarter of 2016, we ceased our drilling program at the end of the first quarter of 2016 and do not have any active drilling planned for the remainder of 2016. The Company currently has six drilled and uncompleted horizontal wells in its inventory, consisting of four standard reach and two extended reach laterals. Until drilling and completion activity resumes, our production will decline in line with our normal decline curves, and we will experience further reductions in revenues, profitability and cash flows. The ultimate amount of capital we will expend may fluctuate materially based on, among other things, market conditions, commodity prices, consummation of restructuring strategies and further changes in the borrowing base under our revolving credit facility.

Results of Operations
 
Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

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Table of Contents

The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated.
 
 
Three Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2016
 
 
2015
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Revenues:
 
 

 
 
 

 
 
 

 
 

Crude oil sales(3)
$
37,884

 
$
60,282

 
$
(22,398
)
 
(37
)%
Natural gas sales(4)
 
6,946

 
 
8,033

 
 
(1,087
)
 
(14
)%
Natural gas liquids sales
 
4,495

 
 
3,834

 
 
661

 
17
 %
Product revenue
$
49,325

 
$
72,149

 
$
(22,824
)
 
(32
)%
 
 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
1,011.7

 
 
1,550.8

 
 
(539.1
)
 
(35
)%
Natural gas (MMcf)
 
3,006.2

 
 
3,766.0

 
 
(759.8
)
 
(20
)%
Natural gas liquids (MBbls)
 
416.2

 
 
485.0

 
 
(68.8
)
 
(14
)%
Crude oil equivalent (MBoe)(1)
 
1,928.9

 
 
2,663.5

 
 
(734.6
)
 
(28
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives)(2):
 
 

 
 
 

 
 
 

 
 
Crude oil (per Bbl)
$
37.45

 
$
38.87

 
$
(1.42
)
 
(4
)%
Natural gas (per Mcf)
$
2.31

 
$
2.13

 
$
0.18

 
8
 %
Natural gas liquids (per Bbl)
$
10.80

 
$
7.91

 
$
2.89

 
37
 %
Crude oil equivalent (per Boe)(1)
$
25.57

 
$
27.09

 
$
(1.52
)
 
(6
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(2):
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
41.74

 
$
62.75

 
$
(21.01
)
 
(33
)%
Natural gas (per Mcf)
$
2.31

 
$
2.32

 
$
(0.01
)
 
 %
Natural gas liquids (per Bbl)
$
10.80

 
$
7.91

 
$
2.89

 
37
 %
Crude oil equivalent (per Boe)(1)
$
27.83

 
$
41.25

 
$
(13.42
)
 
(33
)%
_____________________________
(1)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(2)
The derivatives economically hedge the price we receive for crude oil and natural gas. For the three months ended September 30, 2016 and 2015, the derivative cash settlement gain for oil contracts was $4.3 million and $37.0 million, respectively, and the derivative cash settlement gain for gas contracts was zero and $0.7 million, respectively. Please refer to Note 9 - Derivatives of Part I, Item 1 of this report for additional disclosures.
(3)
Crude oil sales includes $104,000 and $46,000 of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2016 and 2015, respectively.
(4)
Natural gas sales includes $381,000 and $291,000 of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2016 and 2015, respectively.
 
Revenues decreased by 32%, to $49.3 million, for the three months ended September 30, 2016 compared to $72.1 million for the three months ended September 30, 2015 largely due to a 28% decrease in sales volumes, coupled with a 6% decrease in oil equivalent pricing. The decreased volumes are a direct result of decreased drilling and completion activity during the fourth quarter of 2015, the first quarter of 2016, and suspension of drilling and completion activity at the beginning of the second quarter of 2016. During the period from September 30, 2015 through September 30, 2016, we drilled 19 and completed 26 gross wells in the Rocky Mountain region and drilled zero and completed 2 gross wells in the Mid-Continent region, as compared to the period from September 30, 2014 through September 30, 2015, where we drilled 99 and completed 103 gross wells in the Rocky Mountain region and drilled 31 and completed 33 gross wells in the Mid-Continent region.


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Table of Contents

The following table summarizes our operating expenses for the periods indicated.
 
 
Three Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2016
 
 
2015
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Expenses:
 
 

 
 
 

 
 
 

 
 

Lease operating expense
$
9,893

 
$
17,155

 
$
(7,262
)
 
(42
)%
Gas plant and midstream operating expense
 
2,874

 
 
3,081

 
 
(207
)
 
(7
)%
Severance and ad valorem taxes
 
4,100

 
 
2,411

 
 
1,689

 
70
 %
Exploration
 

 
 
6,979

 
 
(6,979
)
 
(100
)%
Depreciation, depletion and amortization
 
27,296

 
 
58,635

 
 
(31,339
)
 
(53
)%
Impairment of oil and gas properties
 

 
 
166,780

 
 
(166,780
)
 
(100
)%
Abandonment and impairment of unproved properties
 
7,682

 
 
1,630

 
 
6,052

 
371
 %
Unused commitments
 
1,688

 
 

 
 
1,688

 
100
 %
General and administrative
 
18,671

 
 
17,818

 
 
853

 
5
 %
Operating Expenses
$
72,204

 
$
274,489

 
$
(202,285
)
 
(74
)%
 
 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe):
 
 

 
 
 

 
 
 

 
 
Lease operating expense
$
5.13

 
$
6.44

 
$
(1.31
)
 
(20
)%
Gas plant and midstream operating expense
 
1.49

 
 
1.16

 
 
0.33

 
28
 %
Severance and ad valorem taxes
 
2.13

 
 
0.91

 
 
1.22

 
134
 %
Exploration
 

 
 
2.62

 
 
(2.62
)
 
(100
)%
Depreciation, depletion and amortization
 
14.15

 
 
22.01

 
 
(7.86
)
 
(36
)%
Impairment of oil and gas properties
 

 
 
62.62

 
 
(62.62
)
 
(100
)%
Abandonment and impairment of unproved properties
 
3.98

 
 
0.61

 
 
3.37

 
552
 %
Unused commitments
 
0.88

 
 

 
 
0.88

 
100
 %
General and administrative
 
9.68

 
 
6.69

 
 
2.99

 
45
 %
Operating Expenses
$
37.44

 
$
103.06

 
$
(65.62
)
 
(64
)%
 
Lease operating expense.  Our lease operating expense decreased $7.3 million, or 42%, to $9.9 million for the three months ended September 30, 2016 from $17.2 million for the three months ended September 30, 2015 and decreased on an equivalent basis from $6.44 per Boe to $5.13 per Boe. The majority of the decrease is due to continued operating cost reductions along with decreased activity levels. The Company reduced operating costs and negotiated contract reductions resulting in decreased pumping and gauging costs of $0.5 million, compression costs of $0.7 million and well servicing costs of $1.5 million during the three months ended September 30, 2016 when compared to the same period in 2015.

Gas plant and midstream operating expense.  Our gas plant and midstream operating expense decreased $0.2 million, or 7%, to $2.9 million for the three months ended September 30, 2016 from $3.1 million for the three months ended September 30, 2015 and increased on an equivalent basis from $1.16 per Boe to $1.49 per Boe. The increase on an equivalent basis is due to a greater decrease in sales volumes than in overall expense on a proportionate basis.
Severance and ad valorem taxes.  Our severance and ad valorem taxes increased 70% to $4.1 million for the three months ended September 30, 2016 from $2.4 million for the three months ended September 30, 2015. Severance and ad valorem taxes primarily correlate to revenue; however, we received a tax refund during the three months ended September 30, 2015, effectively causing the expense to decrease in 2015.
 
Exploration.  Our exploration expense decreased $7.0 million during the three months ended September 30, 2016 when compared to the same period in 2015. During the three months ended September 30, 2016, we incurred zero exploration charges. During the three months ended September 30, 2015, we incurred $6.8 million of charges on wells for which we were unable to assign economic proved reserves relating to exploratory wells located in southern Arkansas.

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Table of Contents

 
Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense decreased $31.3 million, or 53%, to $27.3 million for the three months ended September 30, 2016 from $58.6 million for the three months ended September 30, 2015 and decreased on an equivalent basis from $22.01 per Boe to $14.15 per Boe. The decrease is due primarily to a reduction in the net proved properties depletable base of approximately 41% between the comparable periods.
Impairment of oil and gas properties.  Our impairment of oil and gas properties decreased $166.8 million for the three months ended September 30, 2016 when compared to the three months ended September 30, 2015. There were zero impairment charges during the three months ended September 30, 2016. We impaired our Mid-Continent assets by $166.8 million to their fair value upon classification as assets held for sale during the three months ended September 30, 2015.
Abandonment and impairment of unproved properties.  Our abandonment and impairment of unproved properties increased 371% to $7.7 million for the three months ended September 30, 2016 when compared to the three months ended September 30, 2015. The Company incurred $7.7 million and $1.6 million of impairment charges relating to non-core leases expiring within the Wattenberg Field during the three months ended September 30, 2016 and 2015.
 
Unused commitments. Our unused commitments increased to 1.7 million for the three months ended September 30, 2016 when compared to the three months ended September 30, 2015. The unused commitments expense in 2016 is a result of $1.0 million from deficiency payments for water commitments and $0.7 million from deficiencies on our purchase and transportation agreement. Please see the Liquidity and Capital Resources section of Management's Discussion and Analysis for additional discussion on our purchase and transportation agreements.

General and administrative. Our general and administrative expense increased 5%, to $18.7 million for the three months ended September 30, 2016 from $17.8 million for the comparable period in 2015 and increased on an equivalent basis to $9.68 per Boe from $6.69 per Boe. The increase in general and administrative expense between comparable periods was due to advisory fees related to financing alternatives of $5.9 million. During the three months ended September 30, 2016, we have experienced a decrease in salaries and wages, including related benefits, of $3.3 million and stock compensation of $1.3 million due to reductions in workforce that have occurred since September 30, 2015.
 
Derivative gain (loss).  Our derivative gain decreased $35.7 million to a $2.2 million gain for the three months ended September 30, 2016 when compared to the same period in 2015. The decrease is due to the reduction in hedged volumes and contract prices decreasing at the time of conversion from three-way collars to swaps and puts at the end of the first quarter of 2016 bringing them closer to realized prices during the three months ended September 30, 2016 when compared to the three months ended September 30, 2015. Please refer to Note 9 - Derivatives above for additional discussion.
 
Interest expense.  Our interest expense for the three months ended September 30, 2016 increased 8%, to $15.1 million compared to $14.1 million for the three months ended September 30, 2015. Total interest expense is comprised primarily of interest expense attributable to the Senior Notes including amortization of the premium and financing costs, which was $13.1 million and $13.0 million for the three months ended September 30, 2016 and 2015, respectively. Weighted-average debt outstanding for the three months ended September 30, 2016 was $1.1 billion as compared to $862.0 million for the comparable period in 2015.
 
Income tax benefit. Our estimate for federal and state income tax benefit for the three months ended September 30, 2016 was zero as compared to $68.3 million for the three months ended September 30, 2015. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rates for the three months ended September 30, 2016 and 2015 were 0.0% and 37.8%, respectively. At December 31, 2015, a full valuation allowance was placed against the net deferred tax assets, which caused the Company’s effective tax rate to differ from the U.S. statutory income tax rate. 











22

Table of Contents

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated.
 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2016
 
 
2015
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Revenues:
 
 

 
 
 

 
 
 

 
 

Crude oil sales(3)
$
117,711

 
$
196,205

 
$
(78,494
)
 
(40
)%
Natural gas sales(4)
 
16,270

 
 
23,106

 
 
(6,836
)
 
(30
)%
Natural gas liquids sales
 
14,048

 
 
16,336

 
 
(2,288
)
 
(14
)%
Product revenue
$
148,029

 
$
235,647

 
$
(87,618
)
 
(37
)%
 
 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
3,476.6

 
 
4,574.3

 
 
(1,097.7
)
 
(24
)%
Natural gas (MMcf)
 
9,502.2

 
 
10,808.8

 
 
(1,306.6
)
 
(12
)%
Natural gas liquids (MBbls)
 
1,197.2

 
 
1,315.0

 
 
(117.8
)
 
(9
)%
Crude oil equivalent (MBoe)(1)
 
6,257.5

 
 
7,690.8

 
 
(1,433.3
)
 
(19
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives)(2):
 
 

 
 
 

 
 
 

 
 
Crude oil (per Bbl)
$
33.86

 
$
42.89

 
$
(9.03
)
 
(21
)%
Natural gas (per Mcf)
$
1.71

 
$
2.14

 
$
(0.43
)
 
(20
)%
Natural gas liquids (per Bbl)
$
11.73

 
$
12.42

 
$
(0.69
)
 
(6
)%
Crude oil equivalent (per Boe)(1)
$
23.66

 
$
30.64

 
$
(6.98
)
 
(23
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(2):
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
38.39

 
$
61.76

 
$
(23.37
)
 
(38
)%
Natural gas (per Mcf)
$
1.71

 
$
2.33

 
$
(0.62
)
 
(27
)%
Natural gas liquids (per Bbl)
$
11.73

 
$
12.42

 
$
(0.69
)
 
(6
)%
Crude oil equivalent (per Boe)(1)
$
26.17

 
$
42.13

 
$
(15.96
)
 
(38
)%
_____________________________
(1)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(2)
The derivatives economically hedge the price we receive for crude oil and natural gas. For the nine months ended September 30, 2016 and 2015, the derivative cash settlement gain for oil contracts was $15.7 million and $86.3 million, respectively, and the derivative cash settlement gain for gas contracts for the same periods was zero and $2.0 million, respectively. Please refer to Note 9 - Derivatives of Part I, Item 1 of this report for additional disclosures.
(3)
Crude oil sales includes $387,000 and $46,000 of oil transportation revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2016 and 2015, respectively.
(4)
Natural gas sales includes $1.1 million and $0.4 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2016 and 2015, respectively.
 
Revenues decreased by 37%, to $148.0 million, for the nine months ended September 30, 2016 compared to $235.6 million for the nine months ended September 30, 2015 largely due to a 23% decrease in oil equivalent pricing, coupled with a 19% decrease in sales volumes. The decreased volumes are a direct result of decreased drilling and completion activity during the fourth quarter of 2015, the first quarter of 2016, and suspension of drilling and completion activity at the beginning of the second quarter of 2016. During the period from September 30, 2015 through September 30, 2016, we drilled 19 and completed 26 gross wells in the Rocky Mountain region and drilled zero and completed 2 gross wells in the Mid-Continent region, as compared to the period from September 30, 2014 through September 30, 2015, where we drilled 99 and completed 103 gross wells in the Rocky Mountain region and drilled 31 and completed 33 gross wells in the Mid-Continent region.


23

Table of Contents

The following table summarizes our operating expenses for the periods indicated.
 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2016
 
 
2015
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Expenses:
 
 

 
 
 

 
 
 

 
 

Lease operating expense
$
33,928

 
$
51,710

 
$
(17,782
)
 
(34
)%
Gas plant and midstream operating expense
 
10,198

 
 
8,685

 
 
1,513

 
17
 %
Severance and ad valorem taxes
 
11,531

 
 
13,055

 
 
(1,524
)
 
(12
)%
Exploration
 
943

 
 
13,225

 
 
(12,282
)
 
(93
)%
Depreciation, depletion and amortization
 
84,602

 
 
187,564

 
 
(102,962
)
 
(55
)%
Impairment of oil and gas properties
 
10,000

 
 
166,780

 
 
(156,780
)
 
(94
)%
Abandonment and impairment of unproved properties
 
24,463

 
 
21,627

 
 
2,836

 
13
 %
Unused commitments
 
3,460

 
 

 
 
3,460

 
100
 %
General and administrative
 
49,591

 
 
56,292

 
 
(6,701
)
 
(12
)%
Operating Expenses
$
228,716

 
$
518,938

 
$
(290,222
)
 
(56
)%
 
 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe):
 
 

 
 
 

 
 
 

 
 
Lease operating expense
$
5.42

 
$
6.72

 
$
(1.30
)
 
(19
)%
Gas plant and midstream operating expense
 
1.63

 
 
1.13

 
 
0.50

 
44
 %
Severance and ad valorem taxes
 
1.84

 
 
1.70

 
 
0.14

 
8
 %
Exploration
 
0.15

 
 
1.72

 
 
(1.57
)
 
(91
)%
Depreciation, depletion and amortization
 
13.52

 
 
24.39

 
 
(10.87
)
 
(45
)%
Impairment of oil and gas properties
 
1.60

 
 
21.69

 
 
(20.09
)
 
(93
)%
Abandonment and impairment of unproved properties
 
3.91

 
 
2.81

 
 
1.10

 
39
 %
Unused commitments
 
0.55

 
 

 
 
0.55

 
100
 %
General and administrative
 
7.93

 
 
7.32

 
 
0.61

 
8
 %
Operating Expenses
$
36.55

 
$
67.48

 
$
(30.93
)
 
(46
)%
 
Lease operating expense.  Our lease operating expense decreased $17.8 million, or 34%, to $33.9 million for the nine months ended September 30, 2016 from $51.7 million for the nine months ended September 30, 2015 and decreased on an equivalent basis from $6.72 per Boe to $5.42 per Boe. The decrease is due to continued operating costs reductions along with decreased activity levels. The Company reduced operating costs and negotiated contract reductions resulting in decreased pumping and gauging costs of $2.1 million, compression costs of $3.1 million and well servicing costs of $7.4 million during the nine months ended September 30, 2016 when compared to the same period in 2015.

Gas plant and midstream operating expense.  Our gas plant and midstream operating expense increased $1.5 million, or 17%, to $10.2 million for the nine months ended September 30, 2016 from $8.7 million for the nine months ended September 30, 2015 and increased on an equivalent basis from $1.13 per Boe to $1.63 per Boe. The increase in aggregate and on an equivalent basis is due to RMI's operations beginning during May of 2015.
Severance and ad valorem taxes.  Our severance and ad valorem taxes decreased 12% to $11.5 million for the nine months ended September 30, 2016 from $13.1 million for the nine months ended September 30, 2015. Severance and ad valorem taxes primarily correlate to revenue. Revenues decreased by 37% for the nine months ended September 30, 2016 when compared to the same period in 2015, which was offset by a tax refund received during the third quarter of 2015.
 
Exploration.  Our exploration expense decreased $12.3 million to $0.9 million during the nine months ended September 30, 2016 when compared to the same period in 2015. During the nine months ended September 30, 2016, we had minimal exploration charges. During the nine months ended September 30, 2015, we incurred charges for exploratory wells

24

Table of Contents

located in the North Park Basin and southern Arkansas for $5.7 million and $6.8 million, respectively, for which we were unable to assign economic proved reserves.
 
Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense decreased $103.0 million, or 55%, to $84.6 million for the nine months ended September 30, 2016 from $187.6 million for the nine months ended September 30, 2015 and decreased on an equivalent basis from $24.39 per Boe to $13.52 per Boe. The decrease is due primarily to a reduction in the net proved properties depletable base of approximately 41% between the comparable periods.

Impairment of oil and gas properties. Our impairment of proved properties decreased $156.8 million, to $10.0 million for the nine months ended September 30, 2016 when compared to the same period in 2015. The Company impaired its Dorcheat Field by $10.0 million, based upon the most recent received bid during the first quarter of 2016, when it was held for sale. During the nine months ended September 30, 2015, we impaired our Mid-Continent assets by $166.8 million to their fair value upon classification as assets held for sale.
Abandonment and impairment of unproved properties.  Our abandonment and impairment of unproved properties increased 13% to $24.5 million for the nine months ended September 30, 2016 when compared to the same period in 2015. The Company incurred $24.5 million and $12.9 million of impairment charges relating to non-core leases expiring within the Wattenberg Field during the nine months ended September 30, 2016 and 2015, respectively, and $8.7 million of impairment charges to fully impair the North Park Basin due to a strategic shift in our development plan during the nine months ended September 30, 2015.

Unused commitments. Our unused commitments increased to $3.5 million for the nine months ended September 30, 2016 when compared to the nine months ended September 30, 2015. The unused commitments expense in 2016 is a result of $2.0 million from deficiency payments for water commitments and $1.5 million from deficiencies on our purchase and transportation agreement. Please see the Liquidity and Capital Resources section of Management's Discussion and Analysis for additional discussion on our purchase and transportation agreements.
 
General and administrative. Our general and administrative expense decreased 12%, to $49.6 million for the nine months ended September 30, 2016 from $56.3 million for the comparable period in 2015 and increased on an equivalent basis to $7.93 per Boe from $7.32 per Boe. The decrease between comparable periods in general and administrative expense was due to a reduction in workforce which resulted in a reduction of salaries and wages, including related benefits, of $6.6 million, accrued bonuses of $2.0 million and stock compensation of $3.6 million. These 2016 cost savings were offset by $5.9 million in advisory fees related to financing alternatives incurred during the nine months ended September 30, 2016.
 
Derivative gain (loss).  Our derivative loss increased $63.0 million to a loss of $11.7 million for the nine month period ended September 30, 2016 when compared to the same period in 2015. The decrease is related to a reduction in hedged volumes and contract prices decreasing at the time of conversion from three-way collars to swaps and puts at the end of the first quarter of 2016 bringing them closer to realized prices during the nine months ended September 30, 2016 when compared to the nine months ended September 30, 2015. Please refer to Note 9 - Derivatives above for additional discussion.
 
Interest expense.  Our interest expense for the nine months ended September 30, 2016 increased 8%, to $46.2 million compared to $42.8 million for the nine months ended September 30, 2015. Total interest expense is comprised primarily of interest expense attributable to the Senior Notes including amortization of the premium and financing costs, which was $39.2 million and $39.1 million for the nine month periods ended September 30, 2016 and 2015, respectively. Weighted average debt outstanding for the nine months ended September 30, 2016 was $1.0 billion as compared to $836.0 million for the comparable period in 2015.
 
Income tax benefit. Our estimate for federal and state income tax benefit for the nine months ended September 30, 2016 was zero as compared to $104.8 million for the nine months ended September 30, 2015. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rates for the nine month periods ended September 30, 2016 and 2015 were 0.0% and 37.9%, respectively. As of December 31, 2015, a full valuation allowance was placed against the net deferred tax assets, which caused the Company’s effective tax rate to differ from the U.S. statutory income tax rate. 

Liquidity and Capital Resources
 
Since the first quarter of 2016, the Company’s liquidity outlook has deteriorated due to the Company's inability to sell assets given current market conditions and counterparty concerns about the Company's liquidity and current capital structure, borrowing base reductions that have occurred during 2016, continuation of depressed commodity prices and the inability to access the debt and capital markets. In addition, the Company’s senior secured revolving credit agreement (the “revolving credit facility”) is subject to scheduled redeterminations of its borrowing base, semi-annually, as early as April and October of each year, based primarily on reserve report values using lender commodity price expectations at such time as well as other factors within the discretion of the lenders that are party to the revolving credit facility.

As a result of these and other factors, the following issues have adversely impacted the Company’s ability to continue as a going concern:
the Company’s ability to comply with financial covenants and ratios in its revolving credit facility and indentures has been affected by continued low commodity prices. Among other things, the Company is required under its revolving credit facility to maintain a minimum interest coverage ratio (the “minimum interest coverage ratio”) that must exceed 2.50 to 1.00. Absent a waiver, amendment or forbearance agreement, failure to meet these covenants and ratios would result in an Event of Default (as defined in the revolving credit agreement) and, to the extent the applicable lenders so elect, an acceleration of the Company’s existing indebtedness, causing such debt of $229.3 million, as of September 30, 2016, to be immediately due and payable. Based on the Company's financial results through the third quarter of 2016, it is no longer in compliance with its minimum interest coverage ratio requirement. The minimum interest coverage ratio is calculated by dividing trailing twelve-month EBITDAX by trailing twelve-month interest expense. If a waiver, amendment or forbearance agreement is not obtained, the applicable credit facility lenders could give notice of acceleration as a result of this non-compliance. The Company does not currently have adequate liquidity to repay all of its outstanding debt in full if such debt were accelerated;
because the revolving credit facility borrowing base was redetermined in May 2016 to $200.0 million, the Company was overdrawn by $88.0 million and has been making mandatory monthly repayments of approximately $14.7 million. The borrowing base was further reduced on October 31, 2016 to $150.0 million, which is less than the current amount drawn. Under the terms of the credit agreement, the Company has a 20-day period from the date of redetermination to inform the bank group of its intended method to cure its deficiency. Please refer to Note 5 - Long-Term Debt for additional discussion on the Company's available options to cure its borrowing base deficiency. Depending on its election to cure the deficiency, the Company may not have sufficient cash on hand to be able to make the mandatory repayments associated with curing the deficiency at the time they are due;
the Company’s ability to make interest payments as they become due and repay indebtedness upon maturities (whether under existing terms or as a result of acceleration) is impacted by the Company’s liquidity. As of September 30, 2016, the Company had a $29.3 million borrowing base deficiency under its revolving credit facility and $133.4 million in cash and cash equivalents. As a result of the October 31, 2016 redetermination, the Company's borrowing base deficiency is $64.7 million, as of the date of filing;
the Company has two purchase and transportation agreements to deliver fixed determinable quantities of crude oil. The first agreement went into effect during the second quarter of 2015 for 12,580 barrels per day over an initial five year term. Based on current production estimates, assuming no future drilling and completion activity, the Company anticipates shortfalls in delivering the minimum volume commitments throughout the remainder of 2016. The Company has incurred $1.5 million in minimum volume commitment deficiency payments as of September 30, 2016. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $1.7 million for the remainder of 2016 and an aggregate $44.8 million in deficiency payments for 2017 through April 2020, when the agreement expires. In accordance with an adequate assurance of performance provision contained in the contract, the counterparty withheld $5.0 million from the Company's revenue payment during the third

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quarter of 2016. This payment is being held in a segregated account and is reflected in the other noncurrent assets line item in the accompanying balance sheets. The second agreement became effective on November 1, 2016 for 15,000 barrels per day over an initial seven year term. Based on current production estimates, assuming no future drilling and completion activity, and not designating any barrels to this commitment until May 2020. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $4.8 million in 2016 and an aggregate $165.2 million in deficiency payments for 2017 through October 2023, when the agreement expires. The actual amount of deficiency payments could vary on both contracts depending on the outcome of the Company's ability to renegotiate and execute on one or more of its current liquidity strategies; and
if the Company is unable to obtain a waiver from or otherwise reach an agreement with the lenders under the revolving credit facility and the indebtedness under the revolving credit facility is accelerated, then an Event of Default (as defined in the underlying indentures) under the Company's 6.75% Senior Notes due 2021 (“6.75% Senior Notes”) and 5.75% Senior Notes due 2023 (“5.75% Senior Notes”, collectively referred to as the “Senior Notes”) would occur. If an Event of Default occurs, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes, may declare the entire principal under the Senior Notes to be due and payable immediately. The Company made the October 15, 2016 interest payment of $17.0 million, which included per diem default interest, on its 6.75% Senior Notes to the indenture trustee within the 30-day grace period allowed under the governing indenture. The revolving credit facility and Senior Notes have cross default clauses.

If lenders, and subsequently noteholders, accelerate the Company’s outstanding indebtedness ($1.0 billion as of September 30, 2016), it will become immediately due and payable. In the event of acceleration, the Company does not have sufficient liquidity to repay those amounts and would have to seek relief through a Chapter 11 Bankruptcy proceeding. Due to covenant violations, the Company classified the revolving credit facility and Senior Notes as current liabilities as of September 30, 2016.

The significant risks and uncertainties described above raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. The Company is currently in discussions with various stakeholders, regarding a potential (i) debt for equity exchange or (ii) private secured financing transaction. The Company is also seeking to obtain waivers or amendments from its lenders. There can be no assurance that sufficient liquidity can be obtained from one or more of these actions or that these actions can be consummated within the period needed.


As of September 30, 2016, our borrowing base was $200.0 million, of which we had $229.3 million outstanding on our revolving credit facility, resulting in a borrowing base deficiency of $29.3 million, and no available borrowing capacity. Please refer to Note 5 - Long-term debt above for additional discussion. As of the date of filing, our borrowing base was $150.0 million, resulting in a borrowing base deficiency of $64.7 million, and no available borrowing capacity. Our weighted-average interest rates (excluding amortization of deferred financing costs and the accretion of our contractual obligation for land acquisition) on borrowings from our revolving credit facility were 2.33% and 1.69%, respectively, for the nine months ended September 30, 2016 and 2015. Our commitment fees were $0.5 million and $1.5 million, respectively, for the nine months ended September 30, 2016 and 2015.

For the remainder of 2016, we have oil swaps and puts with quarterly volumes of 2,303 Bbls per day and 4,031 Bbls per day, respectively, with average fixed prices of $52.83 per Bbl and $51.01 per Bbl, respectively. Please refer to Note 9 - Derivatives above for a summary of derivatives in place and Item 3. Quantitative and Qualitative Disclosures About Market Risks below for additional discussion.  

The following table summarizes our cash flows and other financial measures for the periods indicated.

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Nine Months Ended September 30,
 
2016
 
2015
 
(in thousands)
Net cash provided by operating activities
$
30,578

 
$
173,524

Net cash used in investing activities
68,223

 
386,197

Net cash provided by financing activities
149,734

 
235,415

Cash and cash equivalents
133,430

 
25,326

Acquisition of oil and gas properties
919

 
13,602

Exploration and development of oil and gas properties
47,491

 
361,131

 
Cash flows provided by operating activities
 
During the nine month period ended September 30, 2016, we generated $30.6 million of cash provided by operating activities, a decrease of $142.9 million from the comparable period in 2015. The decrease in cash flows from operating activities resulted primarily from an $87.6 million decrease in revenues due to a 23% decrease in oil equivalent pricing and a 19% decrease in sales volumes and a $72.6 million decrease in derivative cash settlements during the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015. See Results of Operations above for more information on the factors driving these changes.
 
Cash flows used in investing activities
 
Net cash used in investing activities for the nine months ended September 30, 2016 decreased $318.0 million as compared to the same period in 2015. For the nine months ended September 30, 2016, cash used for the development of oil and gas properties was $47.5 million, a significant decrease from our prior year drilling program due to lower commodity prices and liquidity constraints. For the nine months ended September 30, 2015, cash used for the acquisition of oil and gas properties was $13.6 million and cash used for the development of oil and gas properties was $361.1 million.
 
Cash flows provided by financing activities
 
Net cash provided by financing activities for the nine months ended September 30, 2016 decreased $85.7 million compared to the same period in 2015. The decrease was primarily due to the difference in borrowings in excess of payments on our revolving credit facility increasing by $114.3 million for the nine months ended September 30, 2016, when compared to the same period in 2015 offset by net proceeds from the sale of common stock of $202.7 million that occurred in 2015.

New Accounting Pronouncements
 
Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this report for any recently issued or adopted accounting standards.
 
Critical Accounting Policies and Estimates
 
Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our 2015 Form 10-K.
 
Effects of Inflation and Pricing
 
Inflation in the United States increased slightly over the past few years, which did not have a material impact on our results of operations for the periods ended September 30, 2016 and 2015. Although the impact of inflation has been relatively insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations, depletion expense, impairment assessments of oil and gas properties, asset retirement obligations, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to

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raise capital, borrow money and retain personnel. Given that oil and gas prices remain depressed, we would anticipate that costs of materials and services to remain at the lower levels we have experienced in the last year.
 
Off-Balance Sheet Arrangements
 
Currently, we do not have any off-balance sheet arrangements.
 
Contractual Obligations
 
There were no material changes in our contractual obligations and other commitments, other than what was disclosed in Note 8 - Commitments and Contingencies, as disclosed in our 2015 Form 10-K.
 
Cautionary Note Regarding Forward-Looking Statements
 
This report contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
 
Forward‑looking statements include statements related to, among other things:
the Company’s ability to continue as a going concern;
the Company's business, liquidity and restructuring strategies;
the Company’s compliance with financial covenants and ratios under its revolving credit facility;

the Company's ability to satisfy its purchase and transportation agreements and resulting deficiency payment obligations;

the Company's ability to restructure its purchase and transportation commitments;
reserves estimates;
estimated sales volumes for 2016;
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
the Wattenberg Field being a premier oil and resource play in the United States;
anticipated continued reduction of costs of materials and services;
anticipated reduction of general and administrative expense and lease operating costs as a result of the measures taken in first quarter 2016 to reduce headcount;
ab