10-Q
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2015
 
 
Commission File Number:  001-35371
 
Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter)
 
Delaware
 
61-1630631
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)

410 17th Street, Suite 1400
 
 
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)
(720) 440-6100
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x  Yes ¨  No
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x  Yes ¨  No
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer x
 
Accelerated filer ¨
 
 
 
Non-accelerated filer ¨
 
Smaller reporting company ¨
(Do not check if a smaller reporting company)
 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨  Yes x  No
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. As of November 2, 2015, the registrant had 49,763,541 shares of common stock outstanding.
 

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Table of Contents

BONANZA CREEK ENERGY, INC.
INDEX
 
 
    
    
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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PART I - FINANCIAL INFORMATION
Item 1.     Financial Statements.
 
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
September 30, 2015
 
December 31, 2014
 
(in thousands, except share data)
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
25,326

 
$
2,584

Accounts receivable:
 

 
 

Oil and gas sales
33,286

 
54,574

Joint interest and other
30,237

 
37,202

Prepaid expenses and other
11,528

 
12,522

Inventory of oilfield equipment
8,747

 
15,353

Derivative asset
60,004

 
86,240

Total current assets
169,128

 
208,475

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

 
 

Proved properties
1,556,942

 
1,924,380

Less: accumulated depreciation, depletion and amortization
(468,173
)
 
(592,073
)
Total proved properties, net
1,088,769

 
1,332,307

Unproved properties
197,770

 
206,721

Wells in progress
89,541

 
139,208

Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $482,496 in 2015 (note 3)
362,922



Natural gas plant, net of accumulated depreciation of $8,457 in 2014

 
67,840

Other property and equipment, net of accumulated depreciation of $8,672 in 2015 and $6,087 in 2014
10,206

 
10,401

Total property and equipment, net
1,749,208

 
1,756,477

Long-term derivative asset
6,900

 
17,765

Other noncurrent assets
18,445

 
23,372

Total assets
$
1,943,681

 
$
2,006,089

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued expenses (note 4)
$
149,063

 
$
145,788

Oil and gas revenue distribution payable
31,446

 
40,659

Contractual obligation for land acquisition
12,000

 
12,000

Total current liabilities
192,509

 
198,447

Long-term liabilities:
 

 
 

Long-term debt (note 5)
875,699

 
840,619

Contractual obligation for land acquisition

 
11,186

Ad valorem taxes
13,226

 
28,635

Deferred income taxes
60,072

 
165,667

Asset retirement obligations
12,539

 
21,464

Asset retirement obligations for assets held for sale
10,086

 

Total liabilities
1,164,131

 
1,266,018

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, 49,767,839 and 41,287,270 issued and outstanding in 2015 and 2014, respectively
49

 
41

Additional paid-in capital
802,866

 
591,511

Retained earnings (deficit)
(23,365
)
 
148,519

Total stockholders’ equity
779,550

 
740,071

Total liabilities and stockholders’ equity
$
1,943,681

 
$
2,006,089

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

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS  AND COMPREHENSIVE INCOME (UNAUDITED)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per share amounts)
Operating net revenues:
 

 
 

 
 

 
 

Oil and gas sales
$
72,149

 
$
156,371

 
$
235,647

 
$
435,448

Operating expenses:
 

 
 

 
 

 
 

Lease operating expense
20,236

 
18,217

 
60,395

 
53,316

Severance and ad valorem taxes
2,411

 
15,334

 
13,055

 
42,347

Exploration
6,979

 
3,291

 
13,225

 
4,470

Depreciation, depletion and amortization
58,635

 
63,241

 
187,564

 
158,489

Impairment of oil and gas properties
166,780




166,780



Abandonment and impairment of unproved properties
1,630

 

 
21,627

 

General and administrative (including $3,164, $3,162, $10,951, and $17,312, respectively, of stock compensation)
17,818

 
14,814

 
56,292

 
63,075

Total operating expenses
274,489

 
114,897

 
518,938

 
321,697

Income (loss) from operations
(202,340
)
 
41,474

 
(283,291
)
 
113,751

Other income (expense):
 

 
 

 
 

 
 

Derivative gain
37,894

 
50,846

 
51,272

 
14,761

Interest expense
(14,073
)
 
(13,228
)
 
(42,779
)
 
(31,997
)
Other income (loss)
(2,077
)
 
181

 
(1,929
)
 
397

Total other income (expense)
21,744

 
37,799

 
6,564

 
(16,839
)
Income (loss) from continuing operations before taxes
(180,596
)
 
79,273

 
(276,727
)
 
96,912

Income tax benefit (expense)
68,297

 
(30,419
)
 
104,843

 
(37,216
)
Income (loss) from continuing operations
$
(112,299
)
 
$
48,854

 
(171,884
)
 
$
59,696

Discontinued operations:
 

 
 

 
 

 
 

Loss from operations associated with oil and gas properties held for sale

 

 

 
(85
)
Gain (loss) on sale of oil and gas properties

 
(117
)
 

 
6,213

Income tax benefit (expense)

 
45

 

 
(2,353
)
Gain (loss) from discontinued operations

 
(72
)
 

 
3,775

Net income (loss)
$
(112,299
)
 
$
48,782

 
$
(171,884
)
 
$
63,471

Comprehensive income (loss)
$
(112,299
)
 
$
48,782

 
$
(171,884
)
 
$
63,471

Basic income (loss) per share:
 

 
 

 
 

 
 

Income (loss) from continuing operations
$
(2.25
)
 
$
1.18

 
$
(3.56
)
 
$
1.47

Income from discontinued operations
$

 
$

 
$

 
$
0.09

Net income (loss) per common share
$
(2.25
)
 
$
1.18

 
$
(3.56
)
 
$
1.56

Diluted income (loss) per share:











Income (loss) from continuing operations
$
(2.25
)

$
1.18


$
(3.56
)

$
1.46

Income from discontinued operations
$


$


$


$
0.09

Net income (loss) per common share
$
(2.25
)

$
1.18


$
(3.56
)

$
1.55

Basic weighted-average common shares outstanding
48,962

 
40,556

 
47,485

 
39,958

Diluted weighted-average common shares outstanding
48,962

 
40,708

 
47,485

 
40,105

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


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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
Nine Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Cash flows from operating activities:
 

 
 

Net income (loss)
$
(171,884
)
 
$
63,471

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
187,564

 
158,557

Deferred income taxes
(105,595
)
 
39,369

Impairment of oil and gas properties
166,780



Abandonment and impairment of unproved properties
21,627

 

Dry hole expense
7,628

 

Stock-based compensation
10,951

 
17,312

Amortization of deferred financing costs and debt premium
1,692

 
1,032

Accretion of contractual obligation for land acquisition
814

 
571

Derivative gain
(51,272
)
 
(14,761
)
Gain on sale of oil and gas properties

 
(6,213
)
Other
283

 
(12
)
Changes in current assets and liabilities:
 
 
 

Accounts receivable
28,253

 
(23,837
)
Prepaid expenses and other assets
994

 
(2,286
)
Accounts payable and accrued liabilities
(11,905
)
 
43,133

Settlement of asset retirement obligations
(778
)
 
(374
)
Net cash provided by operating activities
85,152

 
275,962

Cash flows from investing activities:
 

 
 

Acquisition of oil and gas properties
(13,602
)
 
(178,883
)
Proceeds from sale of oil and gas properties

 
6,000

Payments of contractual obligation
(12,000
)

(12,000
)
Exploration and development of oil and gas properties
(361,018
)
 
(448,586
)
Natural gas plant capital expenditures
(113
)
 
(281
)
Derivative cash settlements
88,372

 
(9,136
)
(Increase) decrease in restricted cash
2,926

 
(3,062
)
Additions to property and equipment - non oil and gas
(2,390
)
 
(5,451
)
Net cash used in investing activities
(297,825
)
 
(651,399
)
Cash flows from financing activities:
 

 
 

Proceeds from credit facility
115,000

 
230,000

Payments to credit facility
(79,000
)
 
(230,000
)
Proceeds from sale of common stock
209,300

 

Offering costs related to sale of common stock
(6,620
)
 

Proceeds from sale of Senior Notes


300,000

Offering costs related to sale of Senior Notes
(99
)
 
(6,867
)
Payment of employee tax withholdings in exchange for the return of common stock
(2,593
)
 
(5,319
)
Deferred financing costs
(573
)
 
(341
)
Net cash provided by financing activities
235,415

 
287,473

Net change in cash and cash equivalents
22,742

 
(87,964
)
Cash and cash equivalents:
 

 
 

Beginning of period
2,584

 
180,582

End of period
$
25,326

 
$
92,618

Supplemental cash flow disclosure:
 

 
 

Cash paid for interest
$
36,759

 
$
18,519

Stock issued for the acquisition of oil and gas properties
$


$
49,050

Stock issued for litigation settlement
$
326


$

Cash paid for income taxes
$
820

 
$
200

Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition
$
(9,441
)
 
$
26,776

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 in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado, which the Company has designated the Rocky Mountain region, and the Dorcheat Macedonia Field in southern Arkansas, which the Company has designated the Mid-Continent region.
 
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, 2014, 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, 2014 (the “2014 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 quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year. The Company evaluated events subsequent to the balance sheet date of September 30, 2015, 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 BCEI 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 2014 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 2014 Form 10-K.
 
Recently Issued Accounting Standards

Effective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”) Update No. 2015-01, Income Statement – Extraordinary and Unusual Items. This update simplifies income statement presentation by eliminating the concept of extraordinary items. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard.

     In April 2015, the FASB issued Update No. 2015-03 – Interest – Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. This authoritative accounting guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years on a retrospective basis. The Company has taken the necessary steps to be ready for adoption of this update which will not have a material effect on the Company’s financial statements or disclosures.

In July 2015, the FASB issued Update No. 2015-11 - Inventory. The update requires that inventory be measured at the lower of cost or net realizable value. 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

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assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

In August 2015, the FASB issued Update No. 2015-14 - Revenue from Contracts with Customers to defer the effective date of the new revenue recognition standard by one year. The new revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.
Rocky Mountain Infrastructure, LLC 
During the first quarter of 2015, the Company’s wholly owned subsidiary, Bonanza Creek Energy Operating Company, LLC, formed a wholly owned subsidiary, Rocky Mountain Infrastructure, LLC, to hold gathering systems, central production facilities and related infrastructure that service the Wattenberg Field.
Discontinued Operations 
During June 2012, the Company sold the majority of its oil and gas properties in California classifying them as discontinued operations with its remaining property being sold in the first quarter of 2014 for approximately $6.0 million. The Company recorded a gain on sale of oil and gas properties in the amount of $6.2 million as of September 30, 2014.  
 
NOTE 3 - ASSETS HELD FOR SALE

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent decreases to the estimated fair value less the costs to sell impact the measurement of assets held for sale.

As of September 30, 2015, the accompanying balance sheets present $362.9 million of assets held for sale, net of accumulated depreciation, depletion, and amortization expense, which consists of all assets in our Rocky Mountain Infrastructure, LLC subsidiary (“RMI”), all assets within our Mid-Continent region and all assets in the North Park Field that the Company no longer intends to develop given the current pricing environment. There is a corresponding asset retirement obligation liability of approximately $10.1 million for assets held for sale recorded in the asset retirement obligations for assets held for sale financial statement line item in the accompanying balance sheets. For the three months ended September 30, 2015, the Company recorded write-downs to fair value less estimated costs to sell of $166.8 million for certain of these assets held for sale. These write-downs are recorded in the impairment of oil and gas properties line item in the accompanying condensed consolidated statements of operations and comprehensive income (“statements of operations”).

Subsequent to September 30, 2015, the Company entered into a purchase agreement with a midstream partner to divest of its Rocky Mountain Infrastructure, LLC subsidiary for total cash consideration of up to $255 million, of which $175 million is to be paid upon closing with the remainder to be paid over the next two consecutive years based on execution of an agreed upon drilling program. The Company expects to close this transaction by January 31, 2016. The closing of this transaction is subject to the satisfaction of customary closing conditions.

The Company determined that none of these potential asset sales qualify for discontinued operations accounting as they did not result in a strategic shift of the Company.

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
 
Accounts payable and accrued expenses contain the following:

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As of September 30,
 
As of December 31,
 
2015
 
2014
 
(in thousands)
Drilling and completion costs
$
73,403

 
$
82,844

Accounts payable trade
3,123

 
5,493

Accrued general and administrative cost
10,996

 
13,541

Lease operating expense
8,248

 
3,569

Accrued reclamation cost
162

 
162

Accrued interest
18,353

 
14,839

Production and ad valorem taxes and other
34,778

 
25,340

Total accounts payable and accrued expenses
$
149,063

 
$
145,788


NOTE 5  - LONG-TERM DEBT
 
Long-term debt consisted of the following as of September 30, 2015 and December 31, 2014:
 
As of September 30,
 
As of December 31,
 
2015
 
2014
 
(in thousands)
Revolving credit facility
$
69,000

 
$
33,000

6.75% Senior Notes due 2021
500,000

 
500,000

Unamortized premium on 6.75% Senior Notes
6,699

 
7,619

5.75% Senior Notes due 2023
300,000

 
300,000

Total long-term debt
$
875,699

 
$
840,619


Credit Facility
 
The Company’s senior secured revolving Credit Agreement, dated March 29, 2011, as amended (the “revolving credit facility”), was further amended on May 13, 2015 (the “2015 Amendment”) to decrease the borrowing base from $600 million to $550 million and subsequently amended on October 19, 2015 to decrease the borrowing base from $550 million to $475 million with the total credit facility size of $1 billion remaining unchanged. The $475 million borrowing base now equals the commitment level under the Credit Agreement. The borrowing base is redetermined semiannually no later than May 15 and November 15. The revolving credit facility is collateralized by substantially all of the Company’s assets and matures on September 15, 2017. As of September 30, 2015,  the Company had $69 million outstanding under the revolving credit facility with an available borrowing capacity of $469 million, if the Company elected to take advantage of the entire $550 million borrowing base available at that date, after reduction for the outstanding letter of credit of $12 million. As of December 31, 2014, the Company had $33 million outstanding under the revolving credit facility with an available borrowing capacity of $543 million, if the Company elected to take advantage of the entire $600 million borrowing base available at that date, after reduction for the outstanding letter of credit of $24 million
 
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 2015 Amendment (i) removed the maximum total debt to trailing twelve month debt to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense and other non-cash charges (“EBITDAX”) covenant of 4.00 to 1.00 and (ii) introduced both a maximum senior secured debt (defined as borrowings under the revolving credit facility, balances drawn under letters of credit, and any outstanding second lien debt) to trailing twelve month EBITDAX covenant of 2.50 to 1.00 and a minimum trailing twelve month interest to trailing twelve month EBITDAX coverage covenant of 2.50 to 1.00. The revolving credit facility also contains a minimum current ratio covenant of 1.00 to 1.00. The Company was in compliance with all financial and non-financial covenants as of September 30, 2015, and through the filing date of this report.
 
Senior Unsecured Notes

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The $500 million aggregate principal amount of 6.75% Senior Notes that mature on April 15, 2021 (“6.75% Senior Notes”) and the $300 million aggregate principal amount of 5.75% Senior Notes that mature on February 1, 2023 (“5.75% Senior Notes” and, together with the 6.75% Senior Notes, the “Senior Notes”) 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 has no independent assets or operations unrelated to its investments in its consolidated subsidiaries. There are no significant restrictions on the Company’s ability or the ability of any subsidiary guarantor to obtain funds from its subsidiaries by such means as a dividend or loan. 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. The Company was in compliance with all covenants under its Senior Notes as of September 30, 2015, and through the filing date of this report.
 
NOTE 6 - COMMITMENTS AND CONTINGENT LIABILITIES

Legal Proceedings 

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

A  purchase and transportation agreement to deliver 12,580 barrels per day of crude oil in the Rocky Mountain region over an initial five year term went into effect May 1, 2015. As of the filing date of this report, the Company did not have any shortfalls in delivering the minimum volumes committed nor do we anticipate any shortfalls for the remainder of 2015.
 
There have been no material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in the 2014 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.
 
During the nine months ended September 30, 2015, the Company granted 594,543 shares of restricted stock under the Company’s LTIP to certain employees and non-employee directors. The fair value of the issuance was $14.4 million. Total expense recorded for restricted stock for the three month periods ended September 30, 2015 and 2014, was $2.5 million and

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$2.6 million, respectively, and $9.0 million and $15.8 million for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, unrecognized compensation cost was $18.5 million and will be amortized through 2018.
 
A summary of the status and activity of non-vested restricted stock for the nine months ended September 30, 2015 is presented below.
 
Restricted
Stock
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year
589,529

 
$
37.66

Granted
594,543

 
$
24.25

Vested
(293,150
)
 
$
23.25

Forfeited
(114,199
)
 
$
35.06

Non-vested at end of quarter
776,723

 
$
29.93

 
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 granted prior to 2014 are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. Satisfaction of the performance conditions for the PSUs granted in 2014 and thereafter 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). For all grants, the PSUs will be settled in shares of the Company’s common stock following the end of the 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. Compensation expense associated with PSUs is recognized as general and administrative expense over the measurement period.
 
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. The following table presents the assumptions used to determine the fair value of the PSUs granted during the nine month period ended September 30, 2015 and for the year ended December 31, 2014.
 
For the Nine Months Ended
 
For the Year Ended
 
September 30, 2015
 
December 31, 2014
Expected term of award
3

 
3
Risk-free interest rate
0.15% - 0.99%

 
0.12% - 0.9%
Expected volatility
65
%
 
40% - 45%
 
During the nine months ended September 30, 2015, the Company granted 144,363 PSUs under the LTIP to certain officers. The fair value of the issuance was $4.8 million. Total expense recorded for PSUs for the three month periods ended September 30, 2015 and 2014 was $642,000 and $392,000, respectively, and $2.0 million and $1.0 million for the nine month periods ended September 30, 2015 and 2014, respectively. As of September 30, 2015, there was $5.9 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2017.
 

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A summary of the status and activity of PSUs for the nine months ended September 30, 2015 is presented below:
 
PSU
 
Weighted-Average
Grant-Date
Fair Value
Non-vested at beginning of year (1)
94,173

 
$
37.55

Granted(1)
144,363

 
$
33.44

Vested(1)

 
$

Forfeited(1)
(16,650
)
 
$
37.00

Non-vested at end of quarter(1)
221,886

 
$
35.77

__________________________________________________________________________
(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.
 
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 September 30, 2015 and December 31, 2014 and their classification within the fair value hierarchy:
 
As of September 30, 2015
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Derivative assets(1)
$

 
$
66,904

 
$

Proved properties(2)
$


$


$
262,976

Unproved properties(2)
$

 
$

 
$
197,770

 
 

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As of December 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Derivative assets(1)
$

 
$
104,005

 
$

Proved properties(2)
$

 
$

 
$
407,900

Asset retirement obligations(3)
$

 
$

 
$
6,200

____________________________________________________________________________
(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 does not reflect the entire asset balance as presented on the accompanying balance sheets. Please refer to the Proved Oil and Gas Properties and Unproved Oil and Gas Properties sections below for additional discussion.
(3)
This represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.
 
Derivatives
 
Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars 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 four 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 fair value of $429.8 million to its fair value of $263.0 million and recognized an impairment of $166.8 million for the nine months ended September 30, 2015. The Company impaired the Dorcheat Macedonia Field which had a carrying value of $519.2 million to its fair value of $391.9 million and recognized an impairment of $127.3 million for the year ended December 31, 2014. The Company impaired the McKamie Patton Field which had a carrying value of $41.0 million to its fair value of $16.0 million and recognized an impairment of $25.0 million for the year ended December 31, 2014. The Company impaired the McCallum Field which had a carrying value of $15.3 million to its fair value of zero and recognized an impairment of $15.3 million for the year ended December 31, 2014.
 
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

12

Table of Contents

the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. The Company impaired non-core acreage in the Wattenberg Field due to lease expirations, which had a carrying value of $210.7 million to its fair value of $197.8 million and recognized an impairment of unproved properties for the nine months ended September 30, 2015 of $12.9 million. The Company also fully impaired the North Park Basin in June 2015, due to a change in the Company’s development plan, recognizing an impairment of unproved properties of $8.7 million. There were no unproved properties measured at fair value as of December 31, 2014.
 
Asset Retirement Obligation
 
The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value as of September 30, 2015.  The Company had $6.2 million of asset retirement obligations recorded at fair value as of December 31, 2014.
 
Long-term Debt
 
As of September 30, 2015, the Company had $500 million of outstanding 6.75% Senior Notes and $300 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 $506.7 million and $507.6 million as of September 30, 2015 and December 31, 2014, respectively. The fair value of the 6.75% Senior Notes as of September 30, 2015 and December 31, 2014 was $350.0 million and $440.0 million, respectively. The 5.75% Senior Notes are recorded at cost on the accompanying balance sheets at $300.0 million as of September 30, 2015 and December 31, 2014. The fair value of the 5.75% Senior Notes as of September 30, 2015 and December 31, 2014 was $198.0 million and $243.0 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 September 30, 2015 and December 31, 2014 was $69.0 million and $33.0 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. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps and collar arrangements for oil and gas and none of the derivative instruments qualify as having hedging relationships.
 

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Table of Contents

As of September 30, 2015, 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/MMBtu
per day)
 
Average
Fixed
Price
 
Average
Short Floor
Price
 
Average
Floor
Price
 
Average
Ceiling
Price
 
Fair Market
Value of Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
Oil
 
 
 
 

 
 

 
 

 
 

 
 

 
 

4Q 2015
 
Swap
 
6,000

 
$
72.16

 
 

 
 

 
 

 
$
14,538

4Q 2015
 
2-Way Collar
 
6,500

 
 

 
 

 
$
84.62

 
$
95.49

 
23,187

2016
 
3-Way Collar
 
5,500

 
 

 
$
70.00

 
$
85.00

 
$
96.83

 
28,496

 
 
 
 
 

 
 

 
 

 
 

 
 

 
$
66,221

Gas
 
 
 
 

 
 

 
 

 
 

 
 

 
 

4Q 2015
 
3-Way Collar
 
15,000

 
 

 
$
3.50

 
$
4.00

 
$
4.75

 
$
683

 
 
 
 
 

 
 

 
 

 
 

 
 

 
$
683

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 

 
 

 
 

 
 

 
 

 
$
66,904

 
Derivative Assets and Liabilities Fair Value
 
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities.
 
The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of September 30, 2015 and December 31, 2014:

 
As of September 30, 2015
 
Balance Sheet Location
 
Fair Value
 
 
 
(in thousands)
Derivative Assets:
 
 
 

Commodity contracts
Current assets
 
$
60,004

Commodity contracts
Noncurrent assets
 
6,900

Derivative Liabilities:
 
 
 

Commodity contracts
Current liabilities
 

Commodity contracts
Long-term liabilities
 

Total derivative asset
 
 
$
66,904

 
 
As of December 31, 2014
 
Balance Sheet Location
 
Fair Value
 
 
 
(in thousands)
Derivative Assets:
 
 
 

Commodity contracts
Current assets
 
$
86,240

Commodity contracts
Noncurrent assets
 
17,765

Derivative Liabilities:
 
 
 

Commodity contracts
Current liabilities
 

Commodity contracts
Long-term liabilities
 

Total derivative asset
 
 
$
104,005



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Table of Contents

The following table summarizes the components of the derivative gain presented on the accompanying statements of operations:
 
Three months ended September 30,
 
Nine months ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Derivative cash settlement gain (loss):
 

 
 

 
 

 
 

Oil contracts(1)
$
37,027

 
$
(1,577
)
 
$
86,325

 
$
(9,171
)
Gas contracts
690

 
583

 
2,047

 
35

Total derivative cash settlement gain (loss)(2)
$
37,717

 
$
(994
)
 
$
88,372

 
$
(9,136
)
 
 
 
 
 
 
 
 
Change in fair value gain (loss)
$
177

 
$
51,840

 
$
(37,100
)
 
$
23,897

 
 
 
 
 
 
 
 
Total derivative gain(3)
$
37,894

 
$
50,846

 
$
51,272

 
$
14,761

____________________________________________________________________________
(1)
During the nine months ended September 30, 2015, the Company paid $10.5 million to convert its three-way collars, scheduled to settle during the third and fourth quarters of 2015, to two-way collars.
(2)
Derivative cash settlement gain (loss) for the nine months ended September 30, 2015 and 2014 is reported in the derivative cash settlements line item on the accompanying statements of cash flows within the net cash used in investing activities.
(3)
Total derivative gain for the nine months ended September 30, 2015 and 2014 is reported in the derivative gain line item 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.
 
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.


15

Table of Contents

The following table sets forth the calculation of income (loss) per basic and diluted shares from continuing and discontinued operations and net income (loss) for the three and nine month periods ended September 30, 2015 and 2014.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per share amounts)
Income (loss) from continuing operations:
 

 
 

 
 

 
 

Income (loss) from continuing operations
$
(112,299
)
 
$
48,854

 
$
(171,884
)
 
$
59,696

Less: undistributed income (loss) to unvested restricted stock
(1,923
)
 
914

 
(2,916
)
 
1,124

Undistributed income (loss) to common shareholders
(110,376
)
 
47,940

 
(168,968
)
 
58,572

Basic income (loss) per common share from continuing operations
$
(2.25
)
 
$
1.18

 
$
(3.56
)
 
$
1.47

Diluted income (loss) per common share from continuing operations
$
(2.25
)
 
$
1.18

 
$
(3.56
)
 
$
1.46

 
 
 
 
 
 
 
 
Income (loss) from discontinued operations:
 

 
 

 
 

 
 

Income (loss) from discontinued operations
$

 
$
(72
)
 
$

 
$
3,775

Less: undistributed income (loss) to unvested restricted stock

 
(1
)
 

 
71

Undistributed income (loss) to common shareholders

 
(71
)
 

 
3,704

Basic income per common share from discontinued operations
$

 
$

 
$

 
$
0.09

Diluted income per common share from discontinued operations
$

 
$

 
$

 
$
0.09

 
 
 
 
 
 
 
 
Net income (loss):
 

 
 

 
 

 
 

Net income (loss)
$
(112,299
)
 
$
48,782

 
$
(171,884
)
 
$
63,471

Less: undistributed income (loss) to unvested restricted stock
(1,923
)
 
913

 
(2,916
)
 
1,195

Undistributed income (loss) to common shareholders
(110,376
)
 
47,869

 
(168,968
)
 
62,276

Basic net income (loss) per common share
$
(2.25
)
 
$
1.18

 
$
(3.56
)
 
$
1.56

Diluted net income (loss) per common share
$
(2.25
)
 
$
1.18

 
$
(3.56
)
 
$
1.55

 
 
 
 
 
 
 
 
Weighted-average shares outstanding - basic
48,962

 
40,556

 
47,485

 
39,958

Add: dilutive effect of contingent PSUs

 
152

 

 
147

Weighted-average shares outstanding - diluted
48,962

 
40,708

 
47,485

 
40,105

The Company was in a net loss position for the three and nine month periods ended September 30, 2015, which made the 156,750 and 265,280 potentially dilutive shares anti-dilutive, respectively.  The Company had no anti-dilutive shares for the three and nine month periods ended September 30, 2014.

NOTE 11 - CAPITAL STOCK
 
On February 6, 2015, the Company completed a public offering of 8,050,000 shares of its common stock generating net proceeds of $202.7 million after deducting underwriter discounts, commissions and offering expenses of approximately $6.6 million. The Company used a portion of the net proceeds to repay all of the then outstanding borrowings under its revolving credit facility and for general corporate purposes, including its drilling and development program and other capital expenditures.

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Table of Contents

NOTE 12 - INCOME TAXES
 
The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. During the three and nine month periods ended September 30, 2015, the effective tax rate was 37.8% and 37.9%, respectively. During the three and nine month periods ended September 30, 2014, the effective tax rate was 38.4%.
 
The deferred income tax liability for an oil and gas exploration company is dependent on many variables such as estimating the economic lives of depleting oil and gas reserves and commodity prices. Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws. 
As of September 30, 2015, 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 2015. 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 very likely adjust only 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, 2014, 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 exploration and production company focused on the extraction of 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, which we have designated the Rocky Mountain region, and the Dorcheat Macedonia Field in southern Arkansas, which we have designated the Mid-Continent region. 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. Our management team has extensive experience operating oil and gas properties and significant expertise in horizontal drilling and fracture stimulation, which we believe will continue to contribute to the development of our sizable inventory of projects, including those targeting the Niobrara and Codell formations in the Rocky Mountain region. Our corporate strategy is to create stockholder value by capitalizing on the existing infrastructure and reduced well costs within the Wattenberg Field and engaging in prudent evaluations of potential acquisitions. We operate approximately 98% of our proved reserves with an average working interest of approximately 89% providing us with significant control over the rate of development of our asset base. Despite the continued uncertainty surrounding the global economy and volatility in commodity prices, we believe the economic returns and economic growth generated by our portfolio of oil and gas assets position us well moving forward.
Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified to conform to the current presentation given the prospective nature of the agreements. The NGL volumes identified by the Company’s gas purchasers are converted to an oil equivalent. The Company believes that this conversion will more accurately convey its production and sales volumes and will allow results to be more comparable with those of our peers. This revision will increase sales volumes and the percentage of sales volumes that relate to NGLs. 
Financial and Operating Highlights
 

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Table of Contents

Our financial results and operational highlights included:
Total liquidity of $494.3 million, consisting of a period-end cash balance plus funds available under our revolving credit facility;
Despite a significant decline in oil and gas prices, the borrowing base under our revolving credit facility only decreased 14% from $550 million to $475 million during the semi-annual redetermination in the third quarter of 2015;
Increased sales volumes by 14% to 2,663.5 MBoe in the third quarter of 2015 from 2,346.4 MBoe in the third quarter of 2014, with oil and NGL production representing 76% of total sales volumes in the third quarter of 2015;
Cash operating costs, which consist of lease operating expense, severance and ad valorem taxes, and the cash portion of general and administrative expense, per barrel decreased by $5.26 per Boe to $14.01 per Boe as compared to the third quarter of 2014;  
Realized a 23% reduction in our drilling and completion costs on our standard reach laterals during 2015 when compared to the same period in 2014; 
As of the third quarter of 2015, we had $362.9 million of assets held for sale representing all assets in our Rocky Mountain Infrastructure, LLC subsidiary, all assets within our Mid-Continent region and all assets in the North Park Field which sales, if consummated, would allow the Company to focus on its core assets within the Wattenberg Field. Subsequent to quarter end, we entered into a purchase agreement to sell our Rocky Mountain Infrastructure, LLC subsidiary for total cash consideration of up to $255 million, of which $175 million is to be paid upon closing. Please refer to Note 3 - Assets Held for Sale above for additional discussion;
Drilled 21 and completed 24 gross wells within our Rocky Mountain region and drilled 8 and completed 7 gross wells within our Mid-Continent region during the third quarter of 2015;
Cash deployed for capital projects during the nine months ended September 30, 2015 was $302.0 million; and 
During 2015, the Company, along with a third-party midstream entity, completed pipeline infrastructure that allowed for connectivity in our east and west legacy acreage in the Wattenberg Field relieving line pressure constraints and allowing more flexibility. 
 
Outlook for 2015
 
Because the global economic outlook, central bank policies and commodity price environment are uncertain, we have planned a flexible capital spending program for the remainder of 2015. We currently estimate the mid-point of our total capital expenditures in 2015 to be approximately $420 million, allocating approximately 90% to the Wattenberg Field and 10% to southern Arkansas. Actual capital expenditures are subject to a number of factors, including economic conditions and commodity prices, and the Company may reduce or augment the capital budget as appropriate during the remainder of the year. During the third quarter of 2015, we revised our annual mid-point sales volume to 28,200 Boe per day.

The Company released one of its two operated rigs during the third quarter of 2015. The Company anticipates drilling the same number of wells in 2015 as originally projected just with a lower average rig count. Due to the current drilling program, the Company underwent a reorganization to better align its employee base with current activity resulting in a one-time $1.2 million severance payout. This will result in an annual savings in general and administrative expense of approximately $5.3 million on a go-forward basis.

The oil and gas industry has experienced depressed commodity prices for a sustained period of time and as a result the Company has incurred impairment charges that are likely to be seen in the near future if commodity prices further decrease.
 
Results of Operations
 

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Table of Contents

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014
 
The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated.
 
 
Three Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2015
 
 
2014
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Revenues:
 
 

 
 
 

 
 
 

 
 

Crude oil sales
$
60,282

 
$
130,764

 
$
(70,482
)
 
(54
)%
Natural gas sales
 
8,033

 
 
20,488

 
 
(12,455
)
 
(61
)%
Natural gas liquids sales
 
3,834

 
 
5,119

 
 
(1,285
)
 
(25
)%
Product revenue
$
72,149

 
$
156,371

 
$
(84,222
)
 
(54
)%
 
 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
1,550.8

 
 
1,524.5

 
 
26.3

 
2
 %
Natural gas (MMcf)
 
3,766.0

 
 
4,305.1

 
 
(539.1
)
 
(13
)%
Natural gas liquids (MBbls)
 
485.0

 
 
104.4

 
 
380.6

 
365
 %
Crude oil equivalent (MBoe)(1)
 
2,663.5

 
 
2,346.4

 
 
317.1

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

 
 
 

 
 
 

 
 
Crude oil (per Bbl)
$
38.87

 
$
85.78

 
$
(46.91
)
 
(55
)%
Natural gas (per Mcf)
$
2.13

 
$
4.76

 
$
(2.63
)
 
(55
)%
Natural gas liquids (per Bbl)
$
7.91

 
$
49.03

 
$
(41.12
)
 
(84
)%
Crude oil equivalent (per Boe)(1)
$
27.09

 
$
66.64

 
$
(39.55
)
 
(59
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(2)(3):
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
62.75

 
$
84.74

 
$
(21.99
)
 
(26
)%
Natural gas (per Mcf)
$
2.32

 
$
4.89

 
$
(2.57
)
 
(53
)%
Natural gas liquids (per Bbl)
$
7.91

 
$
49.03

 
$
(41.12
)
 
(84
)%
Crude oil equivalent (per Boe)(1)
$
41.25

 
$
66.22

 
$
(24.97
)
 
(38
)%
____________________________________________________________________________
(1)
Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified to conform to the current presentation given the prospective nature of the agreements.
(2)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(3)
The derivatives economically hedge the price we receive for crude oil and natural gas.
 
Revenues decreased by 54%, to $72.1 million, for the three months ended September 30, 2015 compared to $156.4 million for the three months ended September 30, 2014 largely due to a 59% decrease in oil equivalent pricing. The decreased pricing was offset by increased sales volumes of 14% for the three months ended September 30, 2015 compared to the same period in 2014. The increased volumes are a direct result of $165.5 million expended for drilling and completion during the last quarter of 2014 and $375.7 million expended during the first three quarters of 2015. During the period from September 30, 2014 through September 30, 2015, we drilled 99 and completed 103 gross wells in the Rocky Mountain region and drilled 31 and completed 33 gross wells in the Mid-Continent region. 


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The following table summarizes our operating expenses for the periods indicated.
 
 
Three Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2015
 
 
2014
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Expenses:
 
 

 
 
 

 
 
 

 
 

Lease operating expense
$
20,236

 
$
18,217

 
$
2,019

 
11
 %
Severance and ad valorem taxes
 
2,411

 
 
15,334

 
 
(12,923
)
 
(84
)%
Exploration
 
6,979

 
 
3,291

 
 
3,688

 
112
 %
Depreciation, depletion and amortization
 
58,635

 
 
63,241

 
 
(4,606
)
 
(7
)%
Impairment of oil and gas properties
 
166,780

 
 

 
 
166,780

 
100
 %
Abandonment and impairment of unproved properties
 
1,630

 
 

 
 
1,630

 
100
 %
General and administrative
 
17,818

 
 
14,814

 
 
3,004

 
20
 %
Operating Expenses
$
274,489

 
$
114,897

 
$
159,592

 
139
 %
 
 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe)(1):
 
 

 
 
 

 
 
 

 
 
Lease operating expense
$
7.60

 
$
7.76

 
$
(0.16
)
 
(2
)%
Severance and ad valorem taxes
 
0.91

 
 
6.54

 
 
(5.63
)
 
(86
)%
Exploration
 
2.62

 
 
1.40

 
 
1.22

 
87
 %
Depreciation, depletion and amortization
 
22.01

 
 
26.95

 
 
(4.94
)
 
(18
)%
Impairment of oil and gas properties
 
62.62

 
 

 
 
62.62

 
100
 %
Abandonment and impairment of unproved properties
 
0.61

 
 

 
 
0.61

 
100
 %
General and administrative
 
6.69

 
 
6.31

 
 
0.38

 
6
 %
Operating Expenses
$
103.06

 
$
48.96

 
$
54.10

 
110
 %
____________________________________________________________________________
(1)
Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified to conform to the current presentation given the prospective nature of the agreements.
 
Lease Operating Expense.  Our lease operating expense increased $2.0 million, or 11%, to $20.2 million for the three months ended September 30, 2015 from $18.2 million for the three months ended September 30, 2014 and decreased on an equivalent basis from $7.76 per Boe to $7.60 per Boe. The increase in aggregate lease operating expense was related to increased sales volumes of 14% during the three months ended September 30, 2015 when compared to the same period in 2014. Our lease operating expense per Boe were commensurate between the three months ended September 30, 2015 and 2014.
 
Severance and ad valorem taxes.  Our severance and ad valorem taxes decreased $12.9 million to $2.4 million for the three months ended September 30, 2015 from $15.3 million for the three months ended September 30, 2014. Severance and ad valorem taxes primarily correlate to revenue. Revenues decreased by 54% for the three months ended September 30, 2015 when compared to the same period in 2014 causing the severance and ad valorem taxes to decrease coupled with a tax refund received during the third quarter of 2015. Additionally, our ad valorem tax credits available for deduction increased in the third quarter of 2015 when compared to the same period in 2014 due to continued development of the Wattenberg Field which further reduced our effective severance tax rate.
 
Exploration.  Our exploration expense increased $3.7 million to $7.0 million during the three months ended September 30, 2015 from $3.3 million for the three months ended September 30, 2014. During the three months ended September 30, 2015, we incurred $6.8 million of charges for exploratory wells located outside of our current development area in southern Arkansas, which we were unable to assign economic proved reserves. 
 

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Table of Contents

Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense decreased $4.6 million, or 7%, to $58.6 million for the three months ended September 30, 2015 from $63.2 million for the three months ended September 30, 2014 and decreased on an equivalent basis from $26.95 per Boe to $22.01 per Boe. The decrease was primarily related to assets held for sale not being depreciated for a portion of the third quarter of 2015 coupled with an increase in production of 14%.

Impairment of oil and gas properties. Our impairment of proved properties increased 100%, to $166.8 million for the three months ended September 30, 2015 when compared to three months ended September 30, 2014. We impaired our Mid-Continent assets by $166.8 million to their fair value upon classification as assets held for sale. There were no impairment charges to oil and gas properties during the three months ended September 30, 2014.
Abandonment and impairment of unproved properties.  Our abandonment and impairment of unproved properties increased 100% to $1.6 million for the three months ended September 30, 2015 when compared to the three months ended September 30, 2014. The Company incurred $1.6 million of impairment charges relating to non-core leases expiring within the Wattenberg Field during the three months ended September 30, 2015. There were no unproved properties impaired during the three months ended September 30, 2014.
 
General and administrative. Our general and administrative expense increased $3.0 million, or 20%, to $17.8 million for the three months ended September 30, 2015 from $14.8 million for the comparable period in 2014 and increased on an equivalent basis to $6.69 per Boe from $6.31 per Boe. For most of the third quarter of 2015, the Company had a higher headcount when compared to the same period in 2014, which resulted in higher wages, benefits, and bonuses of $1.8 million. Due to the current drilling program, the Company underwent a reorganization at the end of the third quarter of 2015 to better align its employee base with current activity resulting in a one-time $1.2 million severance payout
 
Derivative gain.  Our derivative gain decreased $12.9 million to $37.9 million for the three month period ended September 30, 2015 from a $50.8 million gain for the comparable period in 2014. The decrease in gain related to a reduction in hedged volumes during the three months ended September 30, 2015 when compared to the three months ended September 30, 2014. Please refer to Note 9 - Derivatives above for additional discussion.
 
Interest expense.  Our interest expense for the three months ended September 30, 2015 increased 6%, to $14.1 million compared to $13.2 million for the three months ended September 30, 2014. Interest expense, including amortization of the premium and financing costs, on the Senior Notes for the three month periods ended September 30, 2015 and 2014 was $13.0 million and $12.2 million, respectively. Average debt outstanding for the three months ended September 30, 2015 was $862.0 million as compared to $764.9 million for the comparable period in 2014.
 
Income tax benefit (expense). Our estimate for federal and state income tax benefit for the three months ended September 30, 2015 was $68.3 million from continuing operations as compared to income tax expense of $30.4 million for the three months ended September 30, 2014. 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 month periods ended September 30, 2015 and 2014 were 37.8% and 38.4%, respectively, which differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes.


21

Table of Contents

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
 
The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated.
 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2015
 
 
2014
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Revenues:
 
 

 
 
 

 
 
 

 
 

Crude oil sales
$
196,205

 
$
361,955

 
$
(165,750
)
 
(46
)%
Natural gas sales
 
23,106

 
 
58,737

 
 
(35,631
)
 
(61
)%
Natural gas liquids sales
 
16,336

 
 
14,749

 
 
1,587

 
11
 %
CO2 sales
 

 
 
7

 
 
(7
)
 
(100
)%
Product revenue
$
235,647

 
$
435,448

 
$
(199,801
)
 
(46
)%
 
 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
4,574.3

 
 
4,065.1

 
 
509.2

 
13
 %
Natural gas (MMcf)
 
10,808.8

 
 
11,091.4

 
 
(282.6
)
 
(3
)%
Natural gas liquids (MBbls)
 
1,315.0

 
 
285.1

 
 
1,029.9

 
361
 %
Crude oil equivalent (MBoe)(1)
 
7,690.8

 
 
6,198.8

 
 
1492

 
24
 %
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives)(2):
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
42.89

 
$
89.04

 
$
(46.15
)
 
(52
)%
Natural gas (per Mcf)
$
2.14

 
$
5.30

 
$
(3.16
)
 
(60
)%
Natural gas liquids (per Bbl)
$
12.42

 
$
51.73

 
$
(39.31
)
 
(76
)%
Crude oil equivalent (per Boe)(1)
$
30.64

 
$
70.25

 
$
(39.61
)
 
(56
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(2)(3):
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
61.76

 
$
86.78

 
$
(25.02
)
 
(29
)%
Natural gas (per Mcf)
$
2.33

 
$
5.30

 
$
(2.97
)
 
(56
)%
Natural gas liquids (per Bbl)
$
12.42

 
$
51.73

 
$
(39.31
)
 
(76
)%
Crude oil equivalent (per Boe)(1)
$
42.13

 
$
68.77

 
$
(26.64
)
 
(39
)%
____________________________________________________________________________
(1)
Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified to conform to the current presentation given the prospective nature of the agreements.
(2)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(3)
The derivatives economically hedge the price we receive for crude oil and natural gas.
 
Revenues decreased by 46%, to $235.6 million, for the nine months ended September 30, 2015 compared to $435.4 million for the nine months ended September 30, 2014 largely due to a 56% decrease in oil equivalent pricing. The decreased pricing was offset by increased sales volumes of 24% for the nine months ended September 30, 2015 compared to the same period in 2014. The increased volumes are a direct result of $165.5 million expended for drilling and completion during the last quarter of 2014 and $375.7 million expended during the first three quarters of 2015. During the period from September 30, 2014 through September 30, 2015, we drilled 99 and completed 103 gross wells in the Rocky Mountain region and drilled 31 and completed 33 gross wells in the Mid-Continent region. 


22

Table of Contents

The following table summarizes our operating expenses for the periods indicated.
 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
Percent
 
 
2015
 
 
2014
 
 
Change
 
Change
 
 
(In thousands, except percentages)
Expenses:
 
 

 
 
 

 
 
 

 
 

Lease operating expense
$
60,395

 
$
53,316

 
$
7,079

 
13
 %
Severance and ad valorem taxes
 
13,055

 
 
42,347

 
 
(29,292
)
 
(69
)%
Exploration
 
13,225

 
 
4,470

 
 
8,755

 
196
 %
Depreciation, depletion and amortization
 
187,564

 
 
158,489

 
 
29,075

 
18
 %
Impairment of oil and gas properties
 
166,780

 
 

 
 
166,780

 
100
 %
Abandonment and impairment of unproved properties
 
21,627

 
 

 
 
21,627

 
100
 %
General and administrative
 
56,292

 
 
63,075

 
 
(6,783
)
 
(11
)%
Operating Expenses
$
518,938

 
$
321,697

 
$
197,241

 
61
 %
 
 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe)(1):
 
 

 
 
 

 
 
 

 
 

Lease operating expense
$
7.85

 
$
8.60

 
$
(0.75
)
 
(9
)%
Severance and ad valorem taxes
 
1.70

 
 
6.83

 
 
(5.13
)
 
(75
)%
Exploration
 
1.72

 
 
0.72

 
 
1.00

 
139
 %
Depreciation, depletion and amortization
 
24.39

 
 
25.57

 
 
(1.18
)
 
(5
)%
Impairment of proved properties
 
21.69

 
 

 
 
21.69

 
100
 %
Abandonment and impairment of unproved properties
 
2.81

 
 

 
 
2.81

 
100
 %
General and administrative
 
7.32

 
 
10.18

 
 
(2.86
)
 
(28
)%
Operating Expenses
$
67.48

 
$
51.90

 
$
15.58

 
30
 %
____________________________________________________________________________
(1)
Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified to conform to the current presentation given the prospective nature of the agreements.
  
Lease Operating Expense.  Our lease operating expense increased $7.1 million, or 13%, to $60.4 million for the nine months ended September 30, 2015 from $53.3 million for the nine months ended September 30, 2014 and decreased on an equivalent basis from $8.60 per Boe to $7.85 per Boe. The increase in aggregate lease operating expense was related to increased sales volumes of 24% during the nine months ended September 30, 2015 when compared to the same period in 2014. During the nine month period ended September 30, 2015, the largest component of lease operating expense was compression which increased $3.8 million over the comparable period in 2014. The Company generated efficiencies to reduce operating costs and negotiated contract reductions while increasing production for the nine months ended September 30, 2015 driving the per barrel rate down when compared to the same period in 2014.
 
Severance and ad valorem taxes.  Our severance and ad valorem taxes decreased $29.2 million to $13.1 million for the nine months ended September 30, 2015 from $42.3 million for the nine months ended September 30, 2014. Severance and ad valorem taxes primarily correlate to revenue, which decreased by 46% for the nine months ended September 30, 2015 when compared to the same period in 2014. Our ad valorem tax credits available for deduction increased for the nine months ended September 30, 2015 when compared to the same period in 2014 due to continued development of the Wattenberg Field which further reduced our effective severance tax rate.
 
Exploration.  Our exploration expense increased $8.7 million to $13.2 million during the nine months ended September 30, 2015 from $4.5 million for the nine months ended September 30, 2014. During the nine months ended September 30, 2015, we incurred charges for exploratory wells located in the North Park Basin and outside of our current development area in southern Arkansas for $5.7 million and $6.8 million, respectively, which we were unable to assign economic proved reserves and paid $700,000 in delay rentals. During the nine months ended September 30, 2014, we incurred

23

Table of Contents

a $1.0 million dry hole charge related to a vertical well within the Wattenberg Field drilled to test the Lyons formation and incurred $3.2 million of seismic charges for an acquisition project within the Wattenberg Field.   
 
Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense increased $29.1 million, or 18%, to $187.6 million for the nine months ended September 30, 2015 from $158.5 million for the nine months ended September 30, 2014. Our depreciation, depletion and amortization expense per Boe were commensurate between the nine months ended September 30, 2015 and 2014.

Impairment of oil and gas properties. Our impairment of proved properties increased 100%, to $166.8 million for the nine months ended September 30, 2015 when compared to the nine months ended September 30, 2014. We impaired our Mid-Continent assets by $166.8 million to their fair value upon classification as assets held for sale. There were no impairment charges to oil and gas properties during the nine months ended September 30, 2014.
 
Abandonment and impairment of unproved properties.  Our abandonment and impairment of unproved properties increased 100% to $21.6 million for the nine months ended September 30, 2015 when compared to the nine months ended September 30, 2014. The Company incurred $12.9 million of impairment charges for non-core leases expiring within the Wattenberg Field and $8.7 million of impairment charges to fully impair the North Park Basin due to a change in our development plan during the nine months ended September 30, 2015. There were no unproved properties impaired during the nine months ended September 30, 2014.
 
General and administrative. Our general and administrative expense decreased $6.8 million, or 11%, to $56.3 million for the nine months ended September 30, 2015 from $63.1 million for the comparable period in 2014 and decreased on an equivalent basis to $7.32 per Boe from $10.18 per Boe. The decrease in general and administrative expense for the nine months ended September 30, 2015 when compared to the same period in 2014 was primarily due to executive departure costs that occurred in 2014.
 
Derivative gain.  Our derivative gain increased $36.5 million to $51.3 million for the nine months ended September 30, 2015 from a $14.8 million gain for the comparable period in 2014. The gain was primarily the result of realized prices being less than the contract prices to a greater extent during the nine months ended September 30, 2015 when compared to the nine months ended September 30, 2014. Please refer to Note 9 - Derivatives above for additional discussion.
 
Interest expense.  Our interest expense for the nine months ended September 30, 2015 increased $10.8 million, to $42.8 million compared to $32.0 million for the nine months ended September 30, 2014. The increase for the nine months ended September 30, 2015 was primarily due to the issuance of $300 million of 5.75% Senior Notes at the beginning of the third quarter of 2014. Interest expense, including amortization of the premium and financing costs, on the Senior Notes for the nine month periods ended September 30, 2015 and 2014 was $39.1 million and $29.2 million, respectively. Average debt outstanding for the nine months ended September 30, 2015 was $836.0 million as compared to $593.0 million for the comparable period in 2014.
 
Income tax benefit (expense). Our estimate for federal and state income tax benefit for the nine months ended September 30, 2015 was $104.8 million from continuing operations as compared to income tax expense of $37.2 million for the nine months ended September 30, 2014. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rates for the nine months ended September 30, 2015 and 2014 were 37.9% and 38.4%, respectively, which differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes.
 
Liquidity and Capital Resources
 
We fund our operations, capital expenditures and working capital requirements with cash flows from our operating activities, borrowings under our revolving credit facility, divestitures of non-core assets and by accessing the debt and capital markets.
 
We anticipate funding our remaining 2015 capital program with our operating cash flows and borrowings under our revolving credit facility, if necessary. We anticipate funding our 2016 capital program with our operating cash flows and cash received from the sale of our Rocky Mountain Infrastructure, LLC subsidiary. We believe that we will have sufficient cash flows to fund our business for at least the next 12 months. To the extent actual operating results differ from our anticipated results or our borrowing base under our revolving credit facility is redetermined at a substantially lower amount, our liquidity

24

Table of Contents

could be adversely affected. If commodity prices remain constrained or continue to drop, it is possible that our borrowing base will be reduced at our next redetermination, which is set to occur in May 2016. A reduction to our borrowing base would result in less funds available for our drilling program, which could result in a reduced reserve base. We currently anticipate exiting the first quarter of 2016 with nothing drawn upon our revolving credit facility and intend for it to remain as such throughout 2016.
As of September 30, 2015, our borrowing base was $550 million, and we elected to limit our bank commitments to $500 million while reserving the option to access the full $550 million, at the Company’s request. As of September 30, 2015, we had $69 million outstanding on our revolving credit facility, a $12 million letter of credit issued, and $469.0 million of available borrowing capacity. On October 19, 2015, our borrowing base decreased 14% from $550.0 million to $475.0 million, despite a 56% reduction in our oil equivalent pricing. The $475.0 million borrowing base now equals the commitment level under the revolving credit facility. 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 1.69% and 2.06%, respectively, for the nine months ended September 30, 2015 and 2014. Our commitment fees were $1.5 million and $1.4 million, respectively, for the nine months ended September 30, 2015 and 2014.
On February 6, 2015, the Company completed a public offering of 8,050,000 shares of its common stock generating net proceeds of $202.7 million after deducting underwriter discounts, commissions and offering expenses of approximately $6.6 million. The Company used a portion of the net proceeds to repay all of the then outstanding borrowings under its revolving credit facility and used the remaining net proceeds for general corporate purposes, including its drilling and development program and other capital expenditures.

Subsequent to September 30, 2015, the Company entered into a purchase agreement with a midstream partner to divest of its Rocky Mountain Infrastructure, LLC subsidiary for total cash consideration of up to $255 million, of which $175 million is to be paid upon closing with the remainder to be paid over the next two consecutive years based on execution of an agreed upon drilling program. The Company expects to close this transaction by January 31, 2016.
 
For the remainder of 2015, we have 6,500 Bbls per day of oil hedged with two-way collars with an average ceiling of $95.49 per Bbl and average floor of $84.62 per Bbl. For the remainder of 2015, we have 6,000 Bbls per day of oil hedged with swaps with a fixed price of $72.16 per Bbl. For the remainder of 2015, we have 15,000 Mcf per day of natural gas hedged with three-way collars with an average ceiling of $4.75 per Mcf, average floor of $4.00 per Mcf and average short floor of $3.50 per Mcf. These commodity derivatives, along with our swaps represent approximately 53% of our anticipated production for the fourth quarter of 2015. In 2016, we have 5,500 Bbls per day of oil hedged with three-way collars with an average ceiling of $96.83 per Bbl, average floor of $85.00 per Bbl and average short floor of $70.00 per Bbl. We expect that our commodity derivative positions will provide partial stabilization of our expected cash flows from operations. 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.
 
Nine Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Net cash provided by operating activities
$
85,152