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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 June 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 July 27, 2016, the registrant had 49,723,220 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)
 
June 30, 2016
 
December 31, 2015
 
(in thousands, except share data)
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
170,171

 
$
21,341

Accounts receivable:
 

 
 

Oil and gas sales
27,536

 
25,322

Joint interest and other
5,595

 
31,224

Prepaid expenses and other
5,426

 
4,078

Inventory of oilfield equipment
8,721

 
8,543

Derivative asset
4,236

 
29,566

Total current assets
221,685

 
120,074

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

 
 

Proved properties
2,518,080

 
1,618,970

Less: accumulated depreciation, depletion and amortization
(1,644,334
)
 
(943,081
)
Total proved properties, net
873,746

 
675,889

Unproved properties
169,911

 
185,530

Wells in progress
19,585

 
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

 
214,922

Other property and equipment, net of accumulated depreciation of $10,760 in 2016 and $9,407 in 2015
8,259

 
9,729

Total property and equipment, net
1,071,501

 
1,137,266

Other noncurrent assets
4,980

 
2,301

Total assets
$
1,298,166

 
$
1,259,641

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued expenses (note 4)
$
55,130

 
$
96,360

Oil and gas revenue distribution payable
25,638

 
27,613

Revolving line of credit - current portion (note 5)
273,333

 

Contractual obligation for land acquisition

 
12,000

Senior Notes - current portion (note 5)
793,168

 

Total current liabilities
1,147,269

 
135,973

Long-term liabilities:
 

 
 

Long-term debt (note 5)

 
871,666

Ad valorem taxes
6,356

 
17,069

Asset retirement obligations
26,737

 
14,935

Asset retirement obligations for assets held for sale

 
10,591

Total liabilities
1,180,362

 
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, 49,618,876 and 49,754,408 issued and outstanding in 2016 and 2015, respectively
49

 
49

Additional paid-in capital
811,497

 
806,386

Retained deficit
(693,742
)
 
(597,028
)
Total stockholders’ equity
117,804

 
209,407

Total liabilities and stockholders’ equity
$
1,298,166

 
$
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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands, except per share amounts)
Operating net revenues:
 

 
 

 
 

 
 

Oil and gas sales
$
54,530

 
$
90,422

 
$
98,704

 
$
163,498

Operating expenses:
 

 
 

 
 

 
 

Lease operating expense
10,737

 
18,169

 
24,035

 
35,142

Gas plant and midstream operating expense
3,535

 
2,726

 
7,324

 
5,017

Severance and ad valorem taxes
4,277

 
4,148

 
7,431

 
10,644

Exploration
677

 
5,748

 
943

 
6,246

Depreciation, depletion and amortization
30,927

 
69,925

 
57,306

 
128,929

Impairment of oil and gas properties




10,000



Abandonment and impairment of unproved properties
9,875

 
14,527

 
16,781

 
19,996

General and administrative (including $2,380, $4,359, $5,384 and $7,787, respectively, of stock-based compensation)
13,235

 
21,602

 
30,920

 
38,474

Total operating expenses
73,263

 
136,845

 
154,740

 
244,448

Loss from operations
(18,733
)
 
(46,423
)
 
(56,036
)
 
(80,950
)
Other income (expense):
 

 
 

 
 

 
 

Derivative gain (loss)
(12,923
)
 
(5,478
)
 
(13,930
)
 
13,378

Interest expense
(16,527
)
 
(14,468
)
 
(31,074
)
 
(28,706
)
Gain on termination fee (note 3)

 

 
6,000

 

Other gain (loss)
(1,294
)
 
198

 
(1,674
)
 
148

Total other income (expense)
(30,744
)
 
(19,748
)
 
(40,678
)
 
(15,180
)
Loss from operations before taxes
(49,477
)
 
(66,171
)
 
(96,714
)
 
(96,130
)
Income tax benefit

 
25,007

 

 
36,544

Net loss
$
(49,477
)
 
$
(41,164
)
 
$
(96,714
)
 
$
(59,586
)
Comprehensive loss
$
(49,477
)
 
$
(41,164
)
 
$
(96,714
)
 
$
(59,586
)
 
 
 
 
 
 
 
 
Basic net loss per common share
$
(1.00
)
 
$
(0.83
)
 
$
(1.97
)
 
$
(1.25
)
 
 
 
 
 
 
 
 
Diluted net loss per common share
$
(1.00
)

$
(0.83
)

$
(1.97
)

$
(1.25
)
 
 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
49,277

 
48,923

 
49,204

 
46,734

 
 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding
49,277

 
48,923

 
49,204

 
46,734

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)
 
Six Months Ended June 30,
 
2016
 
2015
 
(in thousands)
Cash flows from operating activities:
 

 
 

Net loss
$
(96,714
)
 
$
(59,586
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
57,306

 
128,929

Deferred income tax benefit

 
(36,544
)
Impairment of oil and gas properties
10,000



Abandonment and impairment of unproved properties
16,781

 
19,996

Dry hole expense
966

 
5,680

Stock-based compensation
5,384

 
7,787

Amortization of deferred financing costs and debt premium
2,279

 
1,226

Accretion of contractual obligation for land acquisition

 
698

Derivative (gain) loss
13,930

 
(13,378
)
Derivative cash settlements
11,401

 
50,655

Other
(112
)
 
(43
)
Changes in current assets and liabilities:
 
 
 

Accounts receivable
23,415

 
18,319

Prepaid expenses and other assets
(1,348
)
 
(1,348
)
Accounts payable and accrued liabilities
(28,457
)
 
(23,054
)
Settlement of asset retirement obligations
(75
)
 
(519
)
Net cash provided by operating activities
14,756

 
98,818

Cash flows from investing activities:
 

 
 

Acquisition of oil and gas properties
(816
)
 
(11,914
)
Payments of contractual obligation
(12,000
)


Exploration and development of oil and gas properties
(42,753
)
 
(283,106
)
Increase in restricted cash
(2,535
)
 

Additions to property and equipment - non oil and gas
39

 
(649
)
Net cash used in investing activities
(58,065
)
 
(295,669
)
Cash flows from financing activities:
 

 
 

Proceeds from credit facility
209,000

 
87,000

Payments to credit facility
(14,667
)
 
(77,000
)
Proceeds from sale of common stock

 
209,300

Offering costs related to sale of common stock

 
(6,607
)
Offering costs related to sale of Senior Notes

 
(93
)
Payment of employee tax withholdings in exchange for the return of common stock
(273
)
 
(2,448
)
Deferred restructuring charges
(1,684
)
 

Deferred financing costs
(237
)
 
(545
)
Net cash provided by financing activities
192,139

 
209,607

Net change in cash and cash equivalents
148,830

 
12,756

Cash and cash equivalents:
 

 
 

Beginning of period
21,341

 
2,584

End of period
$
170,171

 
$
15,340

Supplemental cash flow disclosure:
 

 
 

Cash paid for interest
$
28,553

 
$
27,396

Cash paid for income taxes
$

 
$
820

Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition
$
(25,462
)
 
$
(12,935
)
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 our 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”) and the condensed consolidated statements of cash flows (“statements of cash flows”) 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 June 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 borrowing base reduction that occurred in May 2016, the inability to sell assets given current market conditions and counterparty concerns about the Company's liquidity and current capital structure, continuation of depressed commodity prices and the possible 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. Due to continued low commodity prices, cessation of the Company’s drilling program, commodity price related reserve write-downs and higher regulatory scrutiny on reserve based lending, we currently expect our borrowing base to be further reduced during our fall redetermination process.

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, in subsequent reporting periods, as early as the third quarter of 2016, with financial covenants and ratios in its revolving credit facility and indentures has been affected by continued low

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commodity prices. 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 approximately $273.3 million, as of June 30, 2016, to be immediately due and payable. While the Company is currently in compliance, based on the Company’s estimates and expectations for commodity prices in 2016, the Company does not expect to remain in compliance with all of the restrictive covenants contained in its revolving credit facility throughout 2016 unless those requirements are waived or amended. 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 is effectively fully drawn, any reduction of the borrowing base would require mandatory prepayments to the extent existing indebtedness exceeds the new borrowing base. The Company may not have sufficient cash on hand to be able to make any such mandatory prepayments;
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 June 30, 2016, the Company had a $73.3 million borrowing base deficiency under its revolving credit facility and $170.2 million in cash and cash equivalents; and
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, the Company anticipates shortfalls in delivering the minimum volume commitments as early as September 2016. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $2.3 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 second agreement is currently scheduled to take effect on the later of November 1, 2016 or the pipeline completion date, for 15,000 barrels per day over an initial seven year term. Based on current production volumes, the Company believes that it will not be able to designate any barrels to this commitment. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential maximum deficiency payments of $4.8 million in 2016, assuming the pipeline is complete by November 1, 2016, and an aggregate $196.4 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 one or more of its current liquidity strategies.

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 the default continues beyond any applicable cure periods 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. Furthermore, the Company has decided to defer making the August 1, 2016 interest payment of approximately $8.6 million on its 5.75% Senior Notes. The indenture governing the 5.75% Senior Notes permit the Company a 30 day grace period to make the interest payment. If the Company fails to make the interest payment within the grace period, or is otherwise unable to obtain a waiver or suitable relief from the holders of these Senior Notes, an Event of Default will result. If the default continues beyond the grace period, the trustee or holders of at least 25% in the aggregate outstanding principal amount, may declare the 5.75% Senior Notes to be due and payable immediately. The revolving credit facility and Senior Notes have cross default clauses, as such, if the 5.75% Senior Notes are deemed in default, the trustee or holders of at least 25% in the aggregate outstanding principal amount of the 6.75% Senior Notes, may declare the 6.75% Senior Notes due and payable immediately.

If lenders, and subsequently noteholders, accelerate the Company’s outstanding indebtedness (approximately $1.1 billion as of June 30, 2016), it will become immediately due and payable and the Company will not have sufficient liquidity to repay those amounts.

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 and is considering pursuing a

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number of actions including: (i) private issuances of equity or equity-linked securities, debt for equity swaps, or any combination thereof; (ii) in- and out-of-court restructuring transactions; (iii) obtaining waivers or amendments from its lenders; and (iv) continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations. 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 $12.6 million as of June 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 in relation to the Company's leases.

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.

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 going through

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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.

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 current 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. The Company recorded $3.0 million of depletion on the RMI assets in the current quarter 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 six months ended June 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 has worked diligently to sell the asset packages listed above, but ultimately determined that the Company's current balance sheet does not support the sale of such assets due to current market conditions and liquidity concerns. Further, the Company's collateral value under the revolving credit facility would have been negatively impacted by either asset sale, thus mitigating any cash gained from such sale.

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
 
Accounts payable and accrued expenses contain the following:
 
As of June 30,
 
As of December 31,
 
2016
 
2015
 
(in thousands)
Drilling and completion costs
$
6,997

 
$
32,459

Accounts payable trade
880

 
1,085

Accrued general and administrative cost
6,025

 
10,643

Lease operating expense
4,116

 
4,731

Accrued reclamation cost
98

 
162

Accrued interest
14,473

 
14,231

Production and ad valorem taxes and other
22,541

 
33,049

Total accounts payable and accrued expenses
$
55,130

 
$
96,360


NOTE 5 - LONG-TERM DEBT
 
Long-term debt consisted of the following:
 
As of June 30,
 
As of December 31,
 
2016
 
2015
 
(in thousands)
Revolving credit facility
$
273,333

 
$
79,000

6.75% Senior Notes due 2021
500,000

 
500,000

Unamortized premium on 6.75% Senior Notes
5,778

 
6,392

5.75% Senior Notes due 2023
300,000

 
300,000

Less debt issuance costs - Senior Notes
(12,610
)
 
(13,726
)
Total debt, net
1,066,501

 
871,666

Less current portion(1)
(1,066,501
)
 

Total long-term debt
$

 
$
871,666

______________________

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(1)
Due to anticipated covenant violations, the Company classified the revolving credit facility and Senior Notes as current liabilities as of June 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, with 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 June 30, 2016, the Company had $273.3 million outstanding under the revolving credit facility and had a borrowing base deficiency of $73.3 million to be paid back in monthly installments of $14.7 million for a total of six months, with no additional available borrowing capacity.
 
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 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 (defined as earnings before interest expense, income tax expense, depreciation, depletion and amortization expense, and exploration expense and other non-cash charges). 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 our long-term debt to current liabilities did not impact the current ratio. The Company was in compliance with all financial and non-financial covenants as of June 30, 2016, and through the filing date of this report. The Company believes that it will be out of compliance by the end of third quarter 2016.
 
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 our existing and future domestic subsidiaries that guarantee or are borrowers under our 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.

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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. Based on current production estimates, the Company anticipates shortfalls in delivering the minimum volume commitments as early as September 2016. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $2.3 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 second agreement is currently scheduled to take effect on the later of November 1, 2016 or the pipeline completion date for 15,000 barrels per day over an initial seven year term. Based on current production volumes, the Company believes that it will not be able to designate any barrels to this commitment. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential maximum deficiency payments of $4.8 million in 2016, assuming the pipeline is complete by November 1, 2016, and an aggregate $196.4 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 one or more of its current liquidity strategies and future drilling. The Company intends to aggressively pursue restructuring these contracts due to continued low commodity prices, the cessation of the Company's drilling program and the Company's current financial condition, which could possibly include altering the volumes, the term of the contracts, and the deficiency fees. The Company expects to have more clarity around its liquidity strategies and restructuring of its purchase and transportation agreements in the third and forth quarters of 2016.

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 million each subsequent year thereafter. During the second quarter of 2016, the Company made the final $12.0 payment, releasing 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 June 30, 2016 and 2015 was $1.8 million and $3.6 million, respectively, and $4.1 million and $6.5 million for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, unrecognized compensation cost was $8.3 million and will be amortized through 2018.
 

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A summary of the status and activity of non-vested restricted stock for the six months ended June 30, 2016 is presented below.
 
Restricted
Stock
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year
731,818

 
$
29.47

Granted

 
$

Vested
(318,974
)
 
$
32.73

Forfeited
(61,949
)
 
$
23.18

Non-vested at end of quarter
$
350,895

 
$
27.62

 
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 our common stock will be calculated based on which quartile our 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.
 
Total expense recorded for PSUs for the three month period ended June 30, 2016 and 2015 was $0.6 million and $0.9 million, respectively, and $1.3 million for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, there was $3.2 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 six months ended June 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)
(6,529
)
 
$
36.21

Non-vested at end of quarter(1)
108,304

 
$
35.24

____________________________
(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

Subsequent to quarter end, the Company granted 2,921,602 of LTIP units (“units”) 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 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.

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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:
 
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 June 30, 2016 and December 31, 2015 and their classification within the fair value hierarchy:
 
As of June 30, 2016
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Derivative assets(1)
$

 
$
4,236

 
$

Unproved properties(2)
$

 
$

 
$
169,911

 
 
 
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.
 

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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 our derivative arrangements are concentrated with three counterparties, all of which are lenders under the Company’s revolving credit facility.
 
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. The Company impaired the Mid-Continent region which had a carrying value of $110.0 million to its estimated fair value, based on the latest bid at the time, of $100.0 million and recognized an impairment of $10.0 million during the first quarter of 2016. There were no impairments recorded during the second 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 $169.9 million and recognized an impairment of unproved properties of $16.8 million for the six months ended June 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 June 30, 2016. The Company had $2.0 million of asset retirement obligations recorded at fair value as of December 31, 2015.
 

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Long-term Debt

As of June 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, on the accompanying balance sheets at $505.8 million and $506.4 million as of June 30, 2016 and December 31, 2015, respectively. The fair value of the 6.75% Senior Notes as of June 30, 2016 and December 31, 2015 was $202.8 million and $301.3 million, respectively. The 5.75% Senior Notes are recorded at cost on the accompanying balance sheets at $300.0 million as of June 30, 2016 and December 31, 2015. The fair value of the 5.75% Senior Notes as of June 30, 2016 and December 31, 2015 was $122.3 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 floating. The outstanding balance under the revolving credit facility as of June 30, 2016 and December 31, 2015 was $273.3 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. Effective March 10, 2016, the Company converted its three-way collars into fixed price swaps and puts.
 
As of June 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
 
 
 
 
 
 
 
 

3Q 2016
 
Swap
 
2,704
 
$51.78
 
$
449

4Q 2016
 
Swap
 
2,303
 
$52.83
 
653

3Q 2016
 
Put
 
4,733
 
$51.01
 
1,435

4Q 2016
 
Put
 
4,031
 
$51.01
 
1,699

 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
$
4,236

 
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 June 30, 2016 and December 31, 2015:
 
 
 
As of June 30, 2016
 
As of December 31, 2015
 
Balance Sheet Location
 
Fair Value
 
Fair Value
 
 
 
(in thousands)
 
(in thousands)
Derivative Assets:
 
 
 
 
 

Commodity contracts
Current assets
 
$
4,236

 
$
29,566

Commodity contracts
Noncurrent assets
 

 

Derivative Liabilities:
 
 
 

 
 

Commodity contracts
Current liabilities
 

 

Commodity contracts
Long-term liabilities
 

 

Total derivative asset
 
 
$
4,236

 
$
29,566



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The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations:
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
 
(in thousands)
Derivative cash settlement gain:
 

 
 

 
 

 
 

Oil contracts
$
3,893

 
$
14,507

 
$
11,401

 
$
49,298

Gas contracts

 
682

 

 
1,357

Total derivative cash settlement gain(1)
$
3,893

 
$
15,189

 
$
11,401

 
$
50,655

 
 
 
 
 
 
 
 
Change in fair value loss
$
(16,816
)
 
$
(20,667
)
 
$
(25,331
)
 
$
(37,277
)
 
 
 
 
 
 
 
 
Total derivative gain (loss)(1)
$
(12,923
)
 
$
(5,478
)
 
$
(13,930
)
 
$
13,378

_______________________________
(1)
Total derivative gain (loss) and the derivative cash settlement gain for the three and six months ended June 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 unvested participating shareholders and losses to common shareholders only.
 
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 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. Please refer to Note 7- Stock-Based Compensation for additional discussion.

The following table sets forth the calculation of loss per basic and diluted shares for the three and six month periods ended June 30, 2016 and 2015.
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
 
 
 
 
(in thousands, except per share amounts)
Net loss
$
(49,477
)
 
$
(41,164
)
 
$
(96,714
)
 
$
(59,586
)
Less: undistributed loss to unvested restricted stock

 

 

 

Undistributed loss to common shareholders
(49,477
)
 
(41,164
)
 
(96,714
)
 
(59,586
)
Basic net loss per common share
$
(1.00
)
 
$
(0.83
)
 
$
(1.97
)
 
$
(1.25
)
Diluted net loss per common share
$
(1.00
)
 
$
(0.83
)
 
$
(1.97
)
 
$
(1.25
)
 
 
 
 
 
 
 
 
Weighted-average shares outstanding - basic
49,277

 
48,923

 
49,204

 
46,734

Add: dilutive effect of contingent PSUs

 

 

 

Weighted-average shares outstanding - diluted
49,277

 
48,923

 
49,204

 
46,734

The Company was in a net loss position for the three and six months ended June 30, 2016 and 2015, which made any potentially dilutive shares anti-dilutive. There were no dilutive shares for the three and six months ended June 30, 2016. There were 80,906 and 106,644 shares that were anti-dilutive for the three and six months ended June 30, 2015. The participating

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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 six month periods ended June 30, 2016, the effective tax rate was 0.0%, respectively. During the three and six month periods ended June 30, 2015, the effective tax rate was 37.8% and 38.0%, respectively. As of 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 June 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 our 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. Our predecessors were founded in 1999 and we went public in December of 2011. Our shares of common stock are listed for 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 has addressed its current liquidity concerns by pursuing the following potential strategies, including but not limited to (i) private issuances of equity or equity-linked securities, debt for equity swaps, or any combination thereof; (ii) in- and out-of-court restructuring transactions; (iii) obtaining waivers or amendments from our lenders; and (iv) continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations. Please refer to the Liquidity and Capital Resources section below for additional discussion. We ceased all drilling at the end of the first quarter of 2016 and reduced our future operating and corporate costs. During the first quarter 2016, we took measures to reduce corporate costs by reducing headcount resulting in a one-time payment of $2.2 million and an annual expected reduction in general and administrative expense and lease operating costs of $7.6 million and $3.1 million, respectively.

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 will begin acting as Senior Operations Advisor, to be done in his continued capacity as a director of the Company. 

Recent Developments


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The Company has pursued a process to explore financial and transactional alternatives to strengthen its balance sheet and maximize the value of the Company. The Company’s Board of Directors and management are currently in the process of evaluating such alternatives to help provide the Company with financial stability, but no assurance can be given as to the outcome or timing of this process. The Company has retained Perella Weinberg Partners to advise the Company and assist in analyzing and evaluating financial and transactional alternatives, including restructuring options. Davis Polk & Wardwell LLP will continue to provide ongoing corporate and finance representation, including representation in connection with the above activities.
Financial and Operating Results
Our financial and operational results, most of which were adversely impacted by depressed oil, natural gas and NGL prices, include:
Net loss of $49.5 million, as compared to a net loss of $41.2 million for the second quarter 2015;
Our borrowing base under our revolving credit facility decreased $275.0 million during the second quarter 2016 resulting in a borrowing base deficiency of $73.3 million as of June 30, 2016;
Decrease in sales volumes of 17% to 2,115.5 MBoe in the second quarter of 2016 from 2,551.5 MBoe in the second quarter of 2015, with oil and NGL production representing approximately 75% of total sales volumes in the second quarter of 2016;
Cash operating costs, which consist of lease operating expense, gas plant and midstream operating expense, severance and ad valorem taxes, and the cash portion of general and administrative expense, per barrel decreased by $2.68 per Boe to $13.90 per Boe from the second quarter of 2015; and
Retained advisors to assist in evaluating financial and transactional alternatives, including restructuring options.
 
Outlook for 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 remainder of 2016 to range from $7.5 million to $17.5 million. 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. Consequently 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, restructuring options and changes in the borrowing base under our revolving credit facility.

Results of Operations
 
Three Months Ended June 30, 2016 Compared to Three Months Ended June 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 June 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2016
 
 
2015
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Revenues:
 
 

 
 
 

 
 
 

 
 

Crude oil sales
$
45,154

 
$
76,503

 
$
(31,349
)
 
(41
)%
Natural gas sales
 
4,710

 
 
6,931

 
 
(2,221
)
 
(32
)%
Natural gas liquids sales
 
4,666

 
 
6,988

 
 
(2,322
)
 
(33
)%
Product revenue
$
54,530

 
$
90,422

 
$
(35,892
)
 
(40
)%
 
 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
1,181.7

 
 
1,533.0

 
 
(351.3
)
 
(23
)%
Natural gas (MMcf)
 
3,175.3

 
 
3,535.9

 
 
(360.6
)
 
(10
)%
Natural gas liquids (MBbls)
 
404.7

 
 
429.2

 
 
(24.5
)
 
(6
)%
Crude oil equivalent (MBoe)(1)
 
2,115.5

 
 
2,551.5

 
 
(436.0
)
 
(17
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives)(2):
 
 

 
 
 

 
 
 

 
 
Crude oil (per Bbl)
$
38.21

 
$
49.90

 
$
(11.69
)
 
(23
)%
Natural gas (per Mcf)
$
1.48

 
$
1.96

 
$
(0.48
)
 
(24
)%
Natural gas liquids (per Bbl)
$
11.53

 
$
16.28

 
$
(4.75
)
 
(29
)%
Crude oil equivalent (per Boe)(1)
$
25.78

 
$
35.44

 
$
(9.66
)
 
(27
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(2):
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
41.51

 
$
59.37

 
$
(17.86
)
 
(30
)%
Natural gas (per Mcf)
$
1.48

 
$
2.15

 
$
(0.67
)
 
(31
)%
Natural gas liquids (per Bbl)
$
11.53

 
$
16.28

 
$
(4.75
)
 
(29
)%
Crude oil equivalent (per Boe)(1)
$
27.62

 
$
41.39

 
$
(13.77
)
 
(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 June 30, 2016 and 2015, the derivative cash settlement gain for oil contracts was $3.9 million and $14.5 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.
 
Revenues decreased by 40%, to $54.5 million, for the three months ended June 30, 2016 compared to $90.4 million for the three months ended June 30, 2015 largely due to a 27% decrease in oil equivalent pricing, coupled with an 17% decrease in sales volumes. The decreased volumes are a direct result of less capital spent for drilling and completion during the last two quarters of 2015 and the first two quarters of 2016. During the period from June 30, 2015 through June 30, 2016, we drilled 44 and completed 59 gross wells in the Rocky Mountain region and drilled 8 and completed 8 gross wells in the Mid-Continent region, as compared to the period from June 30, 2014 through June 30, 2015, where we drilled 110 and completed 106 gross wells in the Rocky Mountain region and drilled 37 and completed 39 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 June 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2016
 
 
2015
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Expenses:
 
 

 
 
 

 
 
 

 
 

Lease operating expense
$
10,737

 
$
18,169

 
$
(7,432
)
 
(41
)%
Gas plant and midstream operating expense
 
3,535

 
 
2,726

 
 
809

 
30
 %
Severance and ad valorem taxes
 
4,277

 
 
4,148

 
 
129

 
3
 %
Exploration
 
677

 
 
5,748

 
 
(5,071
)
 
(88
)%
Depreciation, depletion and amortization
 
30,927

 
 
69,925

 
 
(38,998
)
 
(56
)%
Abandonment and impairment of unproved properties
 
9,875

 
 
14,527

 
 
(4,652
)
 
(32
)%
General and administrative
 
13,235

 
 
21,602

 
 
(8,367
)
 
(39
)%
Operating Expenses
$
73,263

 
$
136,845

 
$
(63,582
)
 
(46
)%
 
 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe):
 
 

 
 
 

 
 
 

 
 
Lease operating expense
$
5.08

 
$
7.12

 
$
(2.04
)
 
(29
)%
Gas plant and midstream operating expense
 
1.67

 
 
1.07

 
 
0.60

 
56
 %
Severance and ad valorem taxes
 
2.02

 
 
1.63

 
 
0.39

 
24
 %
Exploration
 
0.32

 
 
2.25

 
 
(1.93
)
 
(86
)%
Depreciation, depletion and amortization
 
14.62

 
 
27.41

 
 
(12.79
)
 
(47
)%
Abandonment and impairment of unproved properties
 
4.67

 
 
5.69

 
 
(1.02
)
 
(18
)%
General and administrative
 
6.26

 
 
8.47

 
 
(2.21
)
 
(26
)%
Operating Expenses
$
34.64

 
$
53.64

 
$
(19.00
)
 
(35
)%
 
Lease operating expense.  Our lease operating expense decreased $7.4 million, or 41%, to $10.7 million for the three months ended June 30, 2016 from $18.2 million for the three months ended June 30, 2015 and decreased on an equivalent basis from $7.12 per Boe to $5.08 per Boe. The Company reduced operating costs and negotiated contract reductions resulting in decreased compression costs of $2.2 million and well servicing costs of $3.8 million during the three months ended June 30, 2016 when compared to the same period in 2015.

Gas plant and midstream operating expense.  Our gas plant and midstream operating expense increased $0.8 million, or 30%, to $3.5 million for the three months ended June 30, 2016 from $2.7 million for the three months ended June 30, 2015 and increased on an equivalent basis from $1.07 per Boe to $1.67 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 increased 3% to $4.3 million for the three months ended June 30, 2016 from $4.1 million for the three months ended June 30, 2015. Severance and ad valorem taxes primarily correlate to revenue; however, there was a downward revision to the effective rate being used to calculate accrued tax expense in the three months ended June 30, 2015, effectively causing the expense to decrease in 2015.
 
Exploration.  Our exploration expense decreased $5.1 million to $0.7 million during the three months ended June 30, 2016 when compared to the same period in 2015. During the three months ended June 30, 2016, we incurred $0.6 million of charges for exploratory wells for which we were unable to assign economic proved reserves. During the three months ended June 30, 2015, we incurred $5.7 million of charges on wells for which we were unable to assign economic proved reserves relating to exploratory wells located in the North Park Basin.
 
Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense decreased $39.0 million, or 56%, to $30.9 million for the three months ended June 30, 2016 from $69.9 million for the three months ended June 30, 2015 and decreased on an equivalent basis from $27.41 per Boe to $14.62 per Boe. The decrease is due to the net proved properties depletable base decreasing by approximately 40% between the comparable periods.

20

Table of Contents

Abandonment and impairment of unproved properties.  Our abandonment and impairment of unproved properties decreased 32% to $9.9 million for the three months ended June 30, 2016 when compared to the three months ended June 30, 2015. The Company incurred $9.9 million of impairment charges relating to non-core leases expiring within the Wattenberg Field during the three months ended June 30, 2016. The Company incurred $5.4 million of impairment charges for leases expiring within the Wattenberg Field and $8.7 million of impairment charges to fully impair the North Park Basin due to a strategic shift in the Company's development plan during the three months ended June 30, 2015.
 
General and administrative. Our general and administrative expense decreased 39%, to $13.2 million for the three months ended June 30, 2016 from $21.6 million for the comparable period in 2015 and decreased on an equivalent basis to $6.26 per Boe from $8.47 per Boe. The decrease in general and administrative expense between comparable periods was due to a decrease in salaries and wages, including related benefits, of $3.5 million, bonuses of $2.2 million and stock compensation of $1.8 million due to reductions in workforce that have occurred since June 30, 2015.
 
Derivative gain (loss).  Our derivative loss increased $7.4 million to a $12.9 million loss for the three months ended June 30, 2016 when compared to the same period in 2015. The increase in the loss was primarily the result of 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 June 30, 2016 when compared to the three months ended June 30, 2015. Please refer to Note 9 - Derivatives above for additional discussion.
 
Interest expense.  Our interest expense for the three months ended June 30, 2016 increased 14%, to $16.5 million compared to $14.5 million for the three months ended June 30, 2015. Interest expense, including amortization of the premium and financing costs on the Senior Notes was $13.1 million for the three months ended June 30, 2016 and 2015. Average debt outstanding for the three months ended June 30, 2016 was $1.1 billion as compared to $824.0 million for the comparable period in 2015.
 
Income tax benefit. Our estimate for federal and state income tax benefit for the three months ended June 30, 2016 was zero as compared to $25.0 million for the three months ended June 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 June 30, 2016 and 2015 were 0.0% and 37.8%, 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. 




























21

Table of Contents

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

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

 
 
 

 
 
 

 
 

Crude oil sales
$
79,827

 
$
135,923

 
$
(56,096
)
 
(41
)%
Natural gas sales
 
9,324

 
 
14,919

 
 
(5,595
)
 
(38
)%
Natural gas liquids sales
 
9,553

 
 
12,656

 
 
(3,103
)
 
(25
)%
Product revenue
$
98,704

 
$
163,498

 
$
(64,794
)
 
(40
)%
 
 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
2,465.0

 
 
3,023.5

 
 
(558.5
)
 
(18
)%
Natural gas (MMcf)
 
6,496.0

 
 
7,042.8

 
 
(546.8
)
 
(8
)%
Natural gas liquids (MBbls)
 
781.0

 
 
830.0

 
 
(49.0
)
 
(6
)%
Crude oil equivalent (MBoe)(1)
 
4,328.7

 
 
5,027.3

 
 
(698.6
)
 
(14
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives)(2):
 
 

 
 
 

 
 
 

 
 
Crude oil (per Bbl)
$
32.38

 
$
44.96

 
$
(12.58
)
 
(28
)%
Natural gas (per Mcf)
$
1.44

 
$
2.12

 
$
(0.68
)
 
(32
)%
Natural gas liquids (per Bbl)
$
12.23

 
$
15.25

 
$
(3.02
)
 
(20
)%
Crude oil equivalent (per Boe)(1)
$
22.80

 
$
32.52

 
$
(9.72
)
 
(30
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(2):
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
37.01

 
$
61.26

 
$
(24.25
)
 
(40
)%
Natural gas (per Mcf)
$
1.44

 
$
2.31

 
$
(0.87
)
 
(38
)%
Natural gas liquids (per Bbl)
$
12.23

 
$
15.25

 
$
(3.02
)
 
(20
)%
Crude oil equivalent (per Boe)(1)
$
25.44

 
$
42.60

 
$
(17.16
)
 
(40
)%
_____________________________
(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 six months ended June 30, 2016 and 2015, the derivative cash settlement gain for oil contracts was $11.4 million and $49.3 million, respectively, and the derivative cash settlement gain for gas contracts was zero and $1.4 million, respectively. Please refer to Note 9 - Derivatives of Part I, Item 1 of this report for additional disclosures.
 
Revenues decreased by 40%, to $98.7 million, for the six months ended June 30, 2016 compared to $163.5 million for the six months ended June 30, 2015 largely due to a 30% decrease in oil equivalent pricing, coupled with an 14% decrease in sales volumes. The decreased volumes are a direct result of less capital spent for drilling and completion during the last two quarters of 2015 and the first two quarters of 2016. During the period from June 30, 2015 through June 30, 2016, we drilled 44 and completed 59 gross wells in the Rocky Mountain region and drilled 8 and completed 8 gross wells in the Mid-Continent region, as compared to the period from June 30, 2014 through June 30, 2015, where we drilled 110 and completed 106 gross wells in the Rocky Mountain region and drilled 37 and completed 39 gross wells in the Mid-Continent region.


22

Table of Contents

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

 
 
 

 
 
 

 
 

Lease operating expense
$
24,035

 
$
35,142

 
$
(11,107
)
 
(32
)%
Gas plant and midstream operating expense
 
7,324

 
 
5,017

 
 
2,307

 
46
 %
Severance and ad valorem taxes
 
7,431

 
 
10,644

 
 
(3,213
)
 
(30
)%
Exploration
 
943

 
 
6,246

 
 
(5,303
)
 
(85
)%
Depreciation, depletion and amortization
 
57,306

 
 
128,929

 
 
(71,623
)
 
(56
)%
Impairment of oil and gas properties
 
10,000

 
 

 
 
10,000

 
100
 %
Abandonment and impairment of unproved properties
 
16,781

 
 
19,996

 
 
(3,215
)
 
(16
)%
General and administrative
 
30,920

 
 
38,474

 
 
(7,554
)
 
(20
)%
Operating Expenses
$
154,740

 
$
244,448

 
$
(89,708
)
 
(37
)%
 
 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe):
 
 

 
 
 

 
 
 

 
 
Lease operating expense
$
5.55

 
$
6.99

 
$
(1.44
)
 
(21
)%
Gas plant and midstream operating expense
 
1.69

 
 
1.00

 
 
0.69

 
69
 %
Severance and ad valorem taxes
 
1.72

 
 
2.12

 
 
(0.40
)
 
(19
)%
Exploration
 
0.22

 
 
1.24

 
 
(1.02
)
 
(82
)%
Depreciation, depletion and amortization
 
13.24

 
 
25.65

 
 
(12.41
)
 
(48
)%
Impairment of oil and gas properties
 
2.31

 
 

 
 
2.31

 
100
 %
Abandonment and impairment of unproved properties
 
3.88

 
 
3.98

 
 
(0.10
)
 
(3
)%
General and administrative
 
7.14

 
 
7.65

 
 
(0.51
)
 
(7
)%
Operating Expenses
$
35.75

 
$
48.63

 
$
(12.88
)
 
(26
)%
 
Lease operating expense.  Our lease operating expense decreased $11.1 million, or 32%, to $24.0 million for the six months ended June 30, 2016 from $35.1 million for the six months ended June 30, 2015 and decreased on an equivalent basis from $6.99 per Boe to $5.55 per Boe. The Company reduced operating costs and negotiated contract reductions resulting in decreased pumping and gauging costs of $1.6 million, compression costs of $2.4 million and well servicing costs of $5.9 million during the six months ended June 30, 2016 when compared to the same period in 2015.

Gas plant and midstream operating expense.  Our gas plant and midstream operating expense increased $2.3 million, or 46%, to $7.3 million for the six months ended June 30, 2016 from $5.0 million for the six months ended June 30, 2015 and increased on an equivalent basis from $1.00 per Boe to $1.69 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 30% to $7.4 million for the six months ended June 30, 2016 from $10.6 million for the six months ended June 30, 2015. Severance and ad valorem taxes primarily correlate to revenue. Revenues decreased by 40% for the six months ended June 30, 2016 when compared to the same period in 2015 causing the severance and ad valorem taxes to decrease. 
 
Exploration.  Our exploration expense decreased $5.3 million to $0.9 million during the six months ended June 30, 2016 when compared to the same period in 2015. During the six months ended June 30, 2016 and 2015, we incurred $0.8 million and $5.7 million, respectively, of charges for exploratory wells for which we were unable to assign economic proved reserves. During the six months ended June 30, 2016 and 2015, we incurred $0.1 million and $0.5 million, respectively, in delay rentals.
 

23

Table of Contents

Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense decreased $71.6 million, or 56%, to $57.3 million for the six months ended June 30, 2016 from $128.9 million for the six months ended June 30, 2015 and decreased on an equivalent basis from $25.65 per Boe to $13.24 per Boe. The decrease is due to the net proved properties depletable base decreasing by approximately 40% between the comparable periods.

Impairment of oil and gas properties. Our impairment of proved properties was up $10.0 million for the six months ended June 30, 2016 when compared to the same period in 2015. The Company impaired its Dorcheat Field to the latest received bid at the time during the six months ended June 30, 2016. There were no proved property impairments for the six months ended June 30, 2015.
Abandonment and impairment of unproved properties.  Our abandonment and impairment of unproved properties decreased 16% to $16.8 million for the six months ended June 30, 2016 when compared to the six months ended June 30, 2015. The Company incurred $16.8 million and $10.9 million of impairment charges relating to non-core leases expiring within the Wattenberg Field during the six months ended June 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 six months ended June 30, 2015.
 
General and administrative. Our general and administrative expense decreased 20%, to $30.9 million for the six months ended June 30, 2016 from $38.5 million for the comparable period in 2015 and decreased on an equivalent basis to $7.14 per Boe from $7.65 per Boe. The decrease between comparable periods in general and administrative expense was due to a decrease in salaries and wages, including related benefits, of $3.3 million, accrued bonuses of $3.3 million, and stock compensation of $2.5 million, offset by an increase of $1.6 million for executive severance and $0.6 million of severance for other employees who were part of the reduction in workforce.
 
Derivative gain (loss).  Our derivative gain decreased $27.3 million to a $13.9 million loss for the six month period ended June 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 six months ended June 30, 2016 when compared to the six months ended June 30, 2015. Please refer to Note 9 - Derivatives above for additional discussion.
 
Interest expense.  Our interest expense for the six months ended June 30, 2016 increased 8%, to $31.1 million compared to $28.7 million for the six months ended June 30, 2015. Interest expense, including amortization of the premium and financing costs on the Senior Notes was $26.1 million for the six month periods ended June 30, 2016 and 2015. Average debt outstanding for the six months ended June 30, 2016 was $1.0 billion as compared to $822.8 million for the comparable period in 2015.
 
Income tax benefit. Our estimate for federal and state income tax benefit for the six months ended June 30, 2016 was zero as compared to $36.5 million for the six months ended June 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 six month periods ended June 30, 2016 and 2015 were 0.0% and 38.0%, 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 borrowing base reduction that occurred in May 2016, the inability to sell assets given current market conditions and counterparty concerns about the Company's liquidity and current capital structure, continuation of depressed commodity prices and the possible 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. Due to continued low commodity prices, cessation of the Company’s drilling program, commodity price related reserve write-downs and higher regulatory scrutiny on reserve based lending, we currently expect our borrowing base to be further reduced during our fall redetermination process.

As a result of these and other factors, the following issues have adversely impacted the Company’s ability to continue as a going concern:

24

Table of Contents

the Company’s ability to comply, in subsequent reporting periods, as early as the third quarter of 2016, with financial covenants and ratios in its revolving credit facility and indentures has been affected by continued low commodity prices. 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 approximately $273.3 million, to be immediately due and payable. While the Company is currently in compliance, based on the Company’s estimates and expectations for commodity prices in 2016, the Company does not expect to remain in compliance with all of the restrictive covenants contained in its revolving credit facility throughout 2016 unless those requirements are waived or amended. 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 is effectively fully drawn, any reduction of the borrowing base would require mandatory prepayments to the extent existing indebtedness exceeds the new borrowing base. The Company may not have sufficient cash on hand to be able to make any such mandatory prepayments;
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 June 30, 2016, the Company had a $73.3 million borrowing base deficiency under its revolving credit facility and $170.2 million in cash and cash equivalents; and
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, the Company anticipates shortfalls in delivering the minimum volume commitments as early as September 2016. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of $2.3 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 second agreement is currently scheduled to take effect on the later of November 1, 2016 or the pipeline completion date for 15,000 barrels per day over an initial seven year term. Based on current production volumes, the Company believes that it will not be able to designate any barrels to this commitment. Under the current terms of the contract, the anticipated shortfall in delivering the minimum volume commitments could result in potential maximum deficiency payments of $4.8 million in 2016, assuming the pipeline is complete by November 1, 2016, and an aggregate $196.4 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 one or more of its current liquidity strategies.

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 and 5.75% Senior Notes would occur. If the default continues beyond any applicable cure periods 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. Furthermore, the Company has decided to defer making the August 1, 2016 interest payment of approximately $8.6 million on its 5.75% Senior Notes. The indenture governing the 5.75% Senior Notes permit the Company a 30 day grace period to make the interest payment. If the Company fails to make the interest payment within the grace period, or is otherwise unable to obtain a waiver or suitable relief from the holders of these Senior Notes, an Event of Default will result. If the default continues beyond the grace period, the trustee or holders of at least 25% in the aggregate outstanding principal amount, may declare the 5.75% Senior Notes to be due and payable immediately. The revolving credit facility and Senior Notes have cross default clauses, as such, if the 5.75% Senior Notes are deemed in default, the trustee or holders of at least 25% in the aggregate outstanding principal amount of the 6.75% Senior Notes, may declare the 6.75% Senior Notes due and payable immediately.

If lenders, and subsequently noteholders, accelerate the Company’s outstanding indebtedness (approximately $1.1 billion as of June 30, 2016), it will become immediately due and payable and the Company will not have sufficient liquidity to repay those amounts.

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 and is considering pursuing a

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number of actions including: (i) private issuances of equity or equity-linked securities, debt for equity swaps, or any combination thereof; (ii) in- and out-of-court restructuring transactions; (iii) obtaining waivers or amendments from its lenders; and (iv) continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations. 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.

The Company has retained advisors to assist in evaluating financial and transactional alternatives, including restructuring options.
As of June 30, 2016, our borrowing base was $200.0 million, of which we had $273.3 million outstanding on our revolving credit facility, resulting in a borrowing base deficiency of $73.3 million, and no available borrowing capacity. Please refer to Note 5 - Long-term debt above for additional discussion. 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 2.54% and 1.68%, respectively, for the six months ended June 30, 2016 and 2015. Our commitment fees were $0.5 million and $1.1 million, respectively, for the six months ended June 30, 2016 and 2015.

For the remainder of 2016, we have oil swaps and puts with average quarterly volumes ranging from 2,303 to 2,704 Bbls per day and 4,031 to 4,733 Bbls per day, respectively, with average fixed prices ranging from $51.78 to $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.
 
Six Months Ended June 30,
 
2016
 
2015
 
(in thousands)
Net cash provided by operating activities
$
14,756

 
$
98,818

Net cash used in investing activities
58,065

 
295,669

Net cash provided by financing activities
192,139

 
209,607

Cash and cash equivalents
170,171

 
15,340

Acquisition of oil and gas properties
816

 
11,914

Exploration and development of oil and gas properties
42,753

 
283,106

 
Cash flows provided by operating activities
 
During the six month period ended June 30, 2016, we generated $14.8 million of cash provided by operating activities, a decrease of $84.1 million from the comparable period in 2015. The decrease in cash flows from operating activities resulted primarily from a $64.8 million decrease in revenues due to a 30% decrease in oil equivalent pricing and a 14% decrease in sales volumes and a $39.3 million decrease in derivative cash settlements during the six months ended June 30, 2016 as compared to the six months ended June 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 six months ended June 30, 2016 decreased $237.6 million as compared to the same period in 2015. For the six months ended June 30, 2016, cash used for the development of oil and gas properties was $42.8 million. For the six months ended June 30, 2015, cash used for the acquisition of oil and gas properties was $11.9 million and cash used for the development of oil and gas properties was $283.1 million.
 
Cash flows provided by financing activities
 
Net cash provided by financing activities for the six months ended June 30, 2016 decreased $17.5 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 $184.3 million for the six months ended June 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.


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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 June 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 raise capital, borrow money and retain personnel. Given the continued decline in oil and gas prices, 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 6 - 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 and liquidity 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;
reserves estimates;
estimated sales volumes for 2016;

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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;
ability to satisfy obligations related to ongoing operations;
impact of lower commodity prices;
plans to drill or participate in wells including the intent to focus in specific areas or formations;
our estimated revenues and losses;
the timing and success of specific projects;
outcomes and effects of litigation, claims and disputes;
impact of recently issued accounting pronouncements;
the Company’s tax position and future tax adjustments;
our financial position;
the amount and availability of our borrowing base under our revolving credit facility and the effect of future borrowing base redeterminations;
our cash flow and liquidity;
our future production;
the ability of the Company to repay its indebtedness as it becomes due or upon acceleration, if any;
impact of commodity derivative positions;
2016 outlook; and
other statements concerning our operations, economic performance and financial condition.

We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.
 
Factors that could cause actual results to differ materially include, but are not limited to, the following: 
the risk factors discussed in Part I, Item 1A of our 2015 Form 10-K;
further declines or volatility in the prices we receive for our oil, natural gas liquids and natural gas;
general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

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ability of our customers to meet their obligations to us;
our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;
the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;
uncertainties associated with estimates of proved oil and gas reserves and, in particular, probable and possible resources;
the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);
environmental risks;
seasonal weather conditions;
lease stipulations;
drilling and operating risks, including the risks associated with the employment of horizontal drilling techniques;
our ability to acquire adequate supplies of water for drilling and completion operations;
availability of oilfield equipment, services and personnel;
exploration and development risks;
competition in the oil and natural gas industry;
management’s ability to execute our plans to meet our goals;
risks related to our derivative instruments;
our ability to attract and retain key members of our senior management and key technical employees;
our ability to maintain effective internal controls;
access to adequate gathering systems and pipeline take-away capacity to provide adequate infrastructure for the products of our drilling program;
our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;
costs and other risks associated with perfecting title for mineral rights in some of our properties;
continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage;
our ability to execute any financial or transactional strategic alternatives;
availability of funds to operate our business if there is a significant further reduction in our borrowing base; and
other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing.


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All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part II, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 
Item 3.    Quantitative and Qualitative Disclosures About Market Risk.
 
Oil and Natural Gas Price Risk 
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of, and compliance with, production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources.
Commodity Derivative Contracts 
Our primary commodity risk management objective is to reduce volatility in our cash flows. We enter into derivative contracts for oil using NYMEX futures or over-the-counter derivative financial instruments with counterparties who we believe are well-capitalized and have been approved by our board of directors.
The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of oil or otherwise fail to perform. To the extent that we engage in derivative contracts, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.
Presently, all of our derivative arrangements are concentrated with three counterparties, all of which are lenders under our revolving credit facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.
The result of oil market prices exceeding our swap prices requires us to make payment for the settlement of our derivatives, if owed by us, generally up to 15 business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between derivative settlement and payment for revenues earned.
Please refer to Note 9 - Derivatives of Part I, Item 1 of this report for a derivative summary table.
Interest Rates 
As of June 30, 2016,