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, 2014

 

 

Commission File Number:  001-35371

 

Bonanza Creek Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

 

(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. ☒  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). ☒    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.

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes  ☒  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 3, 2014, the registrant had 41,237,932 shares of common stock outstanding.

 

 

 

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BONANZA CREEK ENERGY, INC.

INDEX

 

 

 

 

 

 

 

 

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PART I - FINANCIAL INFORMATION

Item 1.        Financial Statements.

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

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

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS  AND COMPREHENSIVE INCOME (UNAUDITED)

 

 

 

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

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

 

The accompanying notes are an integral part of these 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 (Rocky Mountain region) and the Dorcheat Macedonia Field in Southern Arkansas (Mid-Continent region).

 

NOTE 2 - BASIS OF PRESENTATION

 

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. 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, 2013 (the “2013 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, 2014, 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 condensed consolidated balance sheets (“balance sheets”) include the accounts of BCEI and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Holmes Eastern Company, LLC, Bonanza Creek Energy Upstream LLC, and Bonanza Creek Energy Midstream, 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 2013 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 2013 Form 10-K.

 

Recently Issued Accounting Standards

 

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Update No. 2014-08  - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2014 and is to be applied prospectively. 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 May 2014, the FASB issued Update No. 2014-09  - Revenue From Contracts With Customers. The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

 

In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

 

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In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements – Going Concern that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

 

NOTE 3 - ACQUISITIONS

 

The Company acquired approximately 86,000 gross (34,000 net) acres of oil and gas properties, leasehold mineral interests and related assets located in the Wattenberg Field (“Wattenberg Field Acquisition”) from a private operator. The Company paid approximately $174.6 million (inclusive of customary acquisition costs) in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the time of closing, for the acquired assets. The Wattenberg Field Acquisition had an effective date of June 1, 2014 and closed on July 8, 2014. The results of operations for the Wattenberg Field Acquisition have been included in the Company’s condensed consolidated financial statements from the date of closing. Pro forma information is not presented as the pro forma results would not have been materially different from the information presented in the accompanying condensed consolidated statements of operations and comprehensive income (the “accompanying statements of operations”).

 

The Wattenberg Field Acquisition was recorded using the purchase method of accounting. The initial purchase price will be adjusted for post-closing settlements. The following table summarizes the allocation of consideration paid (inclusive of customary acquisition costs) to the tangible assets acquired and liabilities assumed in the Wattenberg Field Acquisition.

 

 

 

NOTE 4 - DISCONTINUED OPERATIONS

 

During June 2012, the Company began marketing, with intent to sell, all of its oil and gas properties in California classifying them as 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. The Company determined that its intent to sell all of its assets in a region qualified as discontinued operations. The Company sold its remaining property in this region during the first quarter of 2014 for approximately $6.0 million and recorded a gain on the sale of oil and gas properties in the amount of $6.2 million. The carrying amounts of the remaining properties included within assets held for sale classified as discontinued operations are presented below.

 

 

 

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The total revenues, expenses, and income associated with the operation of the oil and gas properties held for sale are presented below.

 

 

 

 

 

 

NOTE 5 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

 

Accounts payable and accrued expenses contain the following:

 

 

 

 

NOTE 6 - LONG-TERM DEBT

 

Credit Facility

 

The Company’s senior secured revolving Credit Agreement (the “Revolver” or “credit facility”), dated March 29, 2011, as amended, was further amended on September 30, 2014, to increase the borrowing base from $450 million (decreased from $525 million following the July 2014 issuance of the Company’s 5.75% Senior Notes) to $600 million. The credit facility has an aggregate potential borrowing amount of $1 billion. The Company elected to limit bank commitments to $500 million while reserving the option to access, at the Company’s request, the full $600 million borrowing base prior to the next semi-annual redetermination on May 15, 2015. The Revolver is collateralized by substantially all of the Company’s assets and matures on September 15, 2018. As of September 30, 2014 and December 31, 2013, the Company had no outstanding balance under the Revolver with an available borrowing capacity of $576 million and $414 million, respectively, after the reduction of the outstanding letter of credit of $24 million and $36 million, respectively.

 

The Revolver restricts, among other items, the payment of dividends, certain additional indebtedness, sales of assets, loans and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of minimum current and debt coverage ratios. The Company was in compliance with all financial and non-financial covenants as of September 30, 2014 and through the filing date of this report.

 

5.75% Senior Notes

 

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On July 15, 2014, the Company issued $300 million aggregate principal amount of 5.75% Senior Notes (the “5.75% Senior Notes”) that mature on February 1, 2023. Interest on the 5.75% Senior Notes began accruing on July 15, 2014, and interest is payable on February 1 and August 1 of each year, beginning on February 1, 2015. The 5.75% Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the 5.75% Senior Notes were $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions. The net proceeds were used to pay off the Company’s outstanding credit facility balance and the remainder will be used for general corporate purposes, which may include funding the drilling and development program and other capital expenditures.

 

At any time prior to August 1, 2017, subject to certain limitations, the Company may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.75% of the principal amount, plus accrued and unpaid interest, with an amount of cash not greater than the net cash proceeds of an equity offering. The Company may redeem all or a part of the 5.75% Senior Notes at any time prior to August 1, 2018 subject to a “make-whole” premium and accrued and unpaid interest. On or after August 1, 2018, the Company may redeem all or a part of the 5.75% Senior Notes at the redemption price of 102.875% for 2018, 101.438% for 2019, and 100.0% for 2020 and thereafter, during the twelve month period beginning on August 1 of each applicable year, in each case, plus accrued and unpaid interest.

 

As of September 30, 2014, and through the filing date of this report, all of the existing subsidiaries of the Company are guarantors of the 5.75% Senior Notes, and all such subsidiaries are 100% owned by the Company. The guarantees by the subsidiaries are full and unconditional (except for customary release provisions) and constitute joint and several obligations of the subsidiaries. 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.

 

NOTE 7 - COMMITMENTS AND CONTINGENT LIABILITIES

 

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 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 date of this filing, there were no material pending or overtly threatened legal actions against the Company of which it is aware.

 

Commitments

 

On October 1, 2014, the Company entered into a purchase and transportation agreement to deliver a fixed determinable quantity of crude oil currently anticipated to take effect during the third quarter of 2016. The minimum quantity commitment of crude oil is 15,000 barrels per day over an initial seven year term which equates to an aggregate financial commitment of approximately $322 million over the initial term. While the volume commitment may be met with Company volumes or third party volumes delegated by the Company, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments.  

 

On October 8, 2014, the Company entered into a purchase and transportation agreement to deliver a fixed determinable quantity of crude oil currently anticipated to take effect during the first quarter of 2015. The minimum quantity commitment of crude oil is 12,580 barrels per day over an initial five year term which equates to an aggregate financial commitment of approximately $218 million over the initial term. While the volume commitment may be met with Company volumes or third party volumes delegated by the Company, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments.

 

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NOTE 8 - STOCK-BASED COMPENSATION

 

Restricted Stock under the Long Term Incentive Plan

 

The Company grants shares of restricted stock, each of which represents one share of the Company’s common stock typically vesting in one-third increments over approximately three years. 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, 2014, the Company granted 228,818 shares of restricted stock under the Company’s Long Term Incentive Program (“LTIP”) to certain employees. The fair value of the issuance was $11.6 million. Total expense recorded for restricted stock for the three month periods ended September 30, 2014 and 2013, was $2.6 million and $2.5 million, respectively, and $15.8 million and $9.2 million for the nine months ended September 30, 2014 and 2013, respectively. As of September 30, 2014, unrecognized compensation cost was $1 million and will be amortized through 2017.

 

During the nine months ended September 30, 2014, the Company issued 9,416 shares of restricted common stock under the LTIP to its non-employee directors. Total expense recorded for non-employee directors for the three month periods ended September 30, 2014 and 2013, was $140,000 and $86,000, respectively and $545,000 and $258,000 for the nine months ended September 30, 2014 and 2013, respectively. These awards vest approximately one year after issuance.

 

A summary of the status and activity of non-vested restricted stock for the nine months ended September 30, 2014 is presented below:

 

 

Performance Stock Units under the Long Term Incentive Plan

 

The Company grants performance stock units (“PSUs”) under the LTIP to certain officers of the Company. The number of shares of the Company’s common stock that may be issued to settle PSUs range 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 during 2014 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 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.

 

During the nine months ended September 30, 2014, the Company granted 63,766 PSUs under the LTIP to certain officers. The fair value of the issuance was $2.7 million. Total expense recorded for PSUs for the three month periods ended September 30, 2014 and 2013 was $392,000 and $102,000, respectively and $1.0 million and $209,000 for the nine month periods ended September 30, 2014 and 2013, respectively. As of September 30, 2014, there was $3.0 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2016.

 

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A summary of the status and activity of PSUs for the nine months ended September 30, 2014 is presented below:

 

 

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NOTE 9 - FAIR VALUE MEASUREMENTS

 

The Company follows fair value measurement authoritative guidance for all assets and liabilities measured at fair value, which 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. A hierarchy for inputs is 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. 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 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 assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 and December 31, 2013 and their classification within the fair value hierarchy:

 

 

 

 

 

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

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valuation hierarchy. Presently, all of our derivative arrangements are concentrated with five counterparties all of which are lenders under the Company’s Revolver.

 

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 discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is a significant management estimate based on the best information available. Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate 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 an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no proved properties measured at fair value at September 30, 2014 or December 31, 2013.

 

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 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, 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 an 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. There were no unproved properties measured at fair value as of September 30, 2014 or December 31, 2013.

 

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 at September 30, 2014 or December 31, 2013.

 

Long-term Debt

 

As of September 30, 2014, the Company had $500 million of outstanding 6.75% Senior Notes (the “6.75% Senior Notes”) and $300 million of outstanding 5.75% Senior Notes. The 6.75% Senior Notes are recorded at cost net of the unamortized premium on the accompanying balance sheets at $507.9 million and $508.8 million as of September 30, 2014 and December 31, 2013, respectively. The fair value of the 6.75%  Senior Notes as of September 30, 2014 and December 31, 2013 was $515.0 million and $527.5 million, respectively. The fair value of the 5.75% Senior Notes as of September 30, 2014 was $294.0 million. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price. The Company’s Revolver, when drawn upon, approximates fair value as the applicable interest rates are floating.

 

NOTE 10 - 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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As of September 30, 2014, and as of the filing date of this report, the Company had the following derivative commodity contracts in place:

 

 

 

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, 2014 and December 31, 2013:

 

 

 

 

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

 

 

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NOTE 11 - 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 0% to 200% of 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 contingency period applicable to such PSUs. Please refer to Note 8 - Stock-Based Compensation, for additional discussion.

 

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The following table sets forth the calculation of earnings per basic and diluted shares from continuing and discontinued operations for the three and nine month periods ended September 30, 2014 and 2013:

 

 

 

The Company had no anti-dilutive shares for the three and nine month periods ended September 30, 2014 and 2013.

 

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, 2014 and 2013 the effective tax rate was 38.4 % and 38.5%, respectively

 

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.

 

The Company has not taken any uncertain tax positions and has no valuation allowances.

 

 

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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, 2013 (the “2013 Form 10-K”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (this “Report”).

 

Executive Summary

 

Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is 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 (Rocky Mountain region) and the Dorcheat Macedonia Field in Southern Arkansas (Mid-Continent region). The predictable, oil-weighted production profile of our Arkansas assets provides a strong cash flow base from which to develop our Wattenberg Field assets, principally the Niobrara and Codell formations in Colorado. Our corporate strategy is to create shareholder value by increasing production in our current assets, while opportunistically seeking strategic acquisitions in our core areas or other high return basins across the United States where we can apply our technical competencies of horizontal drilling and fracture stimulation. We maintain a high working interest in our properties, which allows us to control the pace and magnitude of our capital spending program. Despite the uncertainty surrounding the global economy and volatility in commodity prices, we believe the economic returns and organic growth generated by our portfolio of oil and gas assets positions us well moving forward.

 

Financial and Operating Highlights

 

Our financial results and operational highlights for the third quarter of 2014 included:

 

 

 

 

 

 

 

During the nine months ended September 30, 2014, we had the following financial and operational results:

 

 

 

Outlook for 2014

 

Because the global economic outlook and commodity price environment are uncertain, we have planned a flexible capital spending program. We increased our estimated total capital expenditures for 2014 by $55 million during the third quarter of 2014 to

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be between approximately $630 million to $680 million, allocated approximately 87% to the horizontal development of the Niobrara and Codell formations in the Wattenberg Field and 13% to the vertical development of the Dorcheat Macedonia and McKamie Patton Fields in Southern Arkansas. Actual capital expenditures may fluctuate materially based on, among other things, market conditions, and the success of our drilling results as the year continues to progress and changes in the borrowing base under our revolving credit facility. This capital investment is expected to produce average production volumes of 23,200 Boe/d to 24,200 Boe/d in 2014, while maintaining a strong oil and liquids profile.

 

Results of Continuing Operations

 

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

 

The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated.

 

 

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Revenues increased by 24%, to $156.4 million for the three months ended September 30, 2014 compared to $126.0 million for the three months ended September 30, 2013 due to an increase in oil, natural gas, and natural gas liquids production of 41%, 60%, and 7%, respectively, for the comparable period. The increased volumes were offset by a 14% decrease in crude oil equivalent pricing. The increased volumes are a direct result of the $115.7 million expended for drilling and completion during the last quarter of 2013 and the $485.3 million expended during the nine months ended September 30, 2014. During the period from September 30, 2013 through September 30, 2014, we drilled and completed 100 gross (87.1 net) wells in the Rocky Mountain region and 45 gross (35.9 net) wells in the Mid-Continent region. Our Wattenberg Field natural gas is sold as wet gas without processing into dry gas and NGLs, and therefore, sells at a premium due to its high BTU content.

 

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The following table summarizes our operating expenses for the periods indicated.

 

 

 

Lease Operating Expense.  Our lease operating expenses increased $5.2 million, or 41%, to $18.2 million for the three months ended September 30, 2014 from $13.0 million for the three months ended September 30, 2013 and decreased on an equivalent basis from $7.98 per Boe to $7.76 per Boe. The aggregate increase in lease operating expenses was related to increased production volumes attributable to our drilling program. During the quarter ended September 30, 2014, three of the largest components of lease operating expenses were well servicing, compression, and pumping which increased $1.8 million, $1.2 million and $754,000, respectively, over the comparable period in 2013. The decrease in lease operating expenses on an equivalent basis was primarily related to higher production from our horizontal wells in the Wattenberg Field.

 

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $7.2 million, or 90%, to $15.3 million for the three months ended September 30, 2014 from $8.1 million for the three months ended September 30, 2013. The increase was primarily related to a 44% increase in production volumes during the three months ended September 30, 2014 over the comparable period in 2013. Colorado has higher severance and ad valorem tax rates than Arkansas and contributed a greater percentage of production for the three months ended September 30, 2014 when compared to the same period in 2013. In addition, our increase in new production during 2013 in the Wattenberg Field resulted in a higher than expected lag in the amount of ad valorem tax credits eligible for deduction against severance taxes generated in the current year because ad valorem taxes are not eligible for deduction the first year a well is completed.

 

Exploration.  Our exploration expense increased $1.2 million to $3.3 million during the three months ended September 30, 2014 from $2.1 million for the three months ended September 30, 2013. During the three months ended September 30, 2014 a seismic project in the DJ Basin was completed which resulted in charges of approximately $3.2 million. During the three months ended September 30, 2013, a $1.7 million non-core lease in the North Park Basin expired.

 

Depreciation, depletion and amortization.  Our depreciation, depletion, and amortization expense increased $26.5 million, or 72%, to $63.2 million for the three months ended September 30, 2014 from $36.7 million for the three months ended September 30, 2013. Our depreciation, depletion and amortization expense per Boe increased $4.32 or 19% to $26.95 for the three months ended September 30, 2014, as compared to $22.63 for the three months ended September 30, 2013. This increase was primarily the result of a larger increase in production of 44% versus the corresponding increase in proved developed reserves of 21%.

 

General and administrative. Our general and administrative expense increased $1.0 million, or 7%, to $14.8 million for the three months ended September 30, 2014 from $13.8 million for the comparable period in 2013 and decreased on an equivalent basis to $6.31 per Boe from $8.50 per Boe. During the three months ended September 30, 2014, wages and benefits, including bonuses, were $1.4 million higher than the same period in 2013. The increase in wages and benefits is due to an increase in headcount as a result of our drilling program between the three month periods ended September 30, 2014 and 2013. The decrease in general and administrative expense on an equivalent basis is due to production growth outpacing general and administrative expenses.

 

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Derivative gain (loss).  Our derivative gain increased $67.7 million to $50.8 million for the three month period ended September 30, 2014 from a $16.9 million loss for the comparable period in 2013. The gain incurred was primarily the result of realized prices being less than the contract prices as commodity strip prices, particularly oil, have decreased during the three months ended September 30, 2014. Please refer to Note 10 - Derivatives above for additional discussion.

 

Interest expense.  Our interest expense for the three months ended September 30, 2014 increased $7.0 million, or 113%, to $13.2 million compared to $6.2 million for the three months ended September 30, 2013. The increase for the three months ended September 30, 2014 is primarily due to the $200 million 6.75% Senior Note add-on that occurred during the fourth quarter of 2013 and the issuance of the $300 million 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 three month periods ended September 30, 2014 and 2013 was $12.2 million and $5.2 million, respectively. Average debt outstanding for the three months ended September 30, 2014 was $764.9 million as compared to $313.6 million for the comparable period in 2013.

 

Income tax expense. Our estimate for federal and state income taxes for the three months ended September 30, 2014 was $30.4 million from continuing operations as compared to $11.2 million for the three months ended September 30, 2013. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rate for the three month periods ended September 30, 2014 and 2013 was 38.4% and 38.5%, respectively, which differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

 

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

 

The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated.

 

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Revenues increased by 51%, to $435.4 million for the nine months ended September 30, 2014 compared to $288.8 million for the nine months ended September 30, 2013 due primarily to the increase in oil, natural gas, and natural gas liquids production of 56%, 67%, and 13%, respectively, for the comparable periods. A decrease in average sales price on an equivalent basis of 4% for the nine months ended September 30, 2014 when compared to the same period in 2013 slightly offset the increase in production. Please refer to Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 above for additional discussion.

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The following table summarizes our operating expenses for the periods indicated.

 

 

 

Lease Operating Expense.  Our lease operating expenses increased $16.3 million, or 44%, to $53.3 million for the nine months ended September 30, 2014 from $37.0 million for the nine months ended September 30, 2013 and decreased on an equivalent basis from $9.34 per Boe to $8.60 per Boe. The aggregate increase in lease operating expenses was related to increased production volumes attributable to our drilling program. During the nine months ended September 30, 2014, three of the largest components of lease operating expenses were well servicing, compression, and pumping which increased $7.2 million, $3.8 million and $2.7 million, respectively, over the comparable period in 2013. The decrease in lease operating expenses on an equivalent basis was primarily related to higher production from our horizontal wells in the Wattenberg Field.

 

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $24.1 million, or 132%, to $42.3 million for the nine months ended September 30, 2014 from $18.2 million for the nine months ended September 30, 2013. The increase was primarily related to a 57% increase in production volumes during the nine months ended September 30, 2014 over the comparable period in 2013. Please refer to Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 above for additional discussion.

 

Exploration.  Our exploration expense increased $946,000 to $4.5 million during the nine months ended September 30, 2014 from $3.5 million for the nine months ended September 30, 2013. During 2014, we incurred 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. During 2013, a seismic acquisition project in the Wattenberg Field was completed which resulted in charges of approximately $1.4 million and a non-core lease for $1.7 million in the North Park Basin expired.

 

Depreciation, depletion and amortization.  Our depreciation, depletion, and amortization expense increased $68.9 million, or 77%, to $158.5 million for the nine months ended September 30, 2014 from $89.6 million for the nine months ended September 30, 2013. Our depreciation, depletion and amortization expense per Boe increased $2.93, or 13% to $25.57 for the nine months ended September 30, 2014 as compared to $22.64 for the nine months ended September 30, 2013. This increase is primarily due to a larger increase in production of 57% versus the corresponding increase in proved developed reserves of 21%.

 

General and administrative. Our general and administrative expense increased $22.8 million, or 57%, to $63.1 million for the nine months ended September 30, 2014 from $40.3 million for the comparable period in 2013 and slightly increased on an equivalent basis to $10.18 per Boe from $10.17 per Boe. During the nine months ended September 30, 2014, wages and benefits, including bonuses, were $9.6 million higher than the same period in 2013. Several executive departures in 2014 resulted in cash and stock-based severance of $14.1 million. Please refer to Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 above for additional discussion.

 

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Derivative gain (loss).  Our derivative gain increased $29.2 million to $14.8 million for the nine month period ended September 30, 2014 from a $14.4 million loss for the comparable period in 2013. The gain incurred was primarily the result of realized prices being less than the contract prices. Please refer to Note 10 — Derivatives above for additional discussion.

 

Interest expense.  Our interest expense for the nine months ended September 30, 2014 increased $18.0 million, or 129%, to $32.0 million compared to $14.0 million for the nine months ended September 30, 2013. The increase for the nine months ended September 30, 2014 is primarily due to the $200 million 6.75% Senior Note add-on that occurred during the fourth quarter of 2013 and the issuance of the $300 million 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, 2014 and 2013 was $29.2 million and $10.1 million, respectively. Interest expense on the revolving credit facility was $2.2 million and $3.4 million during the nine month periods ended September 30, 2014 and 2013, respectively. Average debt outstanding for the nine months ended September 30, 2014 was $593.0 million as compared to $262.1 million for the comparable period in 2013.

 

Income tax expense. Our estimate for federal and state income taxes for the nine months ended September 30, 2014 was $37.2 million from continuing operations as compared to $27.6 million for the nine months ended September 30, 2013. Our effective tax rate for the nine month periods ended September 30, 2014 and 2013 was 38.4% and 38.5%, respectively. Please refer to Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 above for additional discussion.

 

Results for Discontinued Operations

 

During June 2012, the Company began marketing, with intent to sell, all of its oil and gas properties in California. 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. The Company determined that our intent to exit an entire region qualified for discontinued operations accounting and these assets have been presented as discontinued operations in the accompanying statements of operations.

 

The majority of these properties were sold in 2012. The remaining property located in the Midway Sunset Field sold on March 21, 2014 for approximately $6.0 million and resulted in a $6.2 million gain. Please refer to Note 4 — Discontinued Operations for additional discussion.

 

There were no operating results for our California properties for the three months ended September 30, 2014. Revenues and operating expenses for the same properties for the three months ended September 30, 2013 were $403,000 and $637,000, respectively. Sales volumes for the three month period ended September 30, 2013 were 41 Boe per day.

 

Revenues and operating expenses for the California properties for the nine months ended September 30, 2014 were $361,000 and $446,000, respectively. Revenues and operating expenses for the California properties for the nine months ended September 30, 2013 were $1.3 million and $1.8 million, respectively. Sales volumes for the nine month periods ended September 30, 2014 and 2013 were 13 Boe per day and 47 Boe per day.

 

Liquidity and Capital Resources

 

We fund our operations, capital expenditures and working capital requirements with cash flows from our operating activities and borrowings under our revolving credit facility. Periodically, we access debt and capital markets and sell non-core properties to provide additional liquidity.

 

We believe that our cash on hand, cash flow from operating activities and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures and operating expenses and comply with our debt covenants for at least the next 12 months. To the extent actual operating results differ from our anticipated results our liquidity could be adversely affected.

 

On May 15, 2014, our borrowing base under the revolving credit facility was increased to $525 million from $450 million. We elected to limit bank commitments to $400 million while reserving the option to access, at the Company’s request, the full $525 million. Upon issuance of our 5.75% Senior Notes on July 15, 2014, our borrowing base was adjusted down to $450 million. On September 30, 2014, our revolving credit facility was amended to increase our borrowing base to $600 million and we elected to limit our bank commitment to $500 million while reserving the option to access the full $600 million at the Company’s request. As of September 30, 2014, we had nil outstanding on our revolving credit facility, a $24 million letter of credit issued, and $576 million available borrowing capacity. Our weighted-average interest rate (excluding amortization of deferred financing costs and the accretion of our contractual obligation for land acquisition) on borrowings from our revolving credit facility was 2.06% and 2.27%,

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respectively, for the nine months ended September 30, 2014 and 2013.  Our commitment fees were $1.4 million and $1.3 million, respectively, for the nine months ended September 30, 2014 and 2013.

 

On July 15, 2014, we issued $300 million of 5.75% Senior Notes that mature on February 1, 2023. Interest on the 5.75% Senior Notes began accruing on July 15, 2014, and we will pay interest on February 1 and August 1 of each year, beginning on February 1, 2015. The net proceeds from the sale of the 5.75% Senior Notes were approximately $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions. The net proceeds were used to pay off the Company’s outstanding credit facility balance and the remainder will be used for general corporate purposes, which may include funding the drilling and development program and other capital expenditures. Please see Note 6 - Long-Term Debt above for additional discussion.

 

On July 8, 2014, we acquired approximately 86,000 gross (34,000 net) acres, leasehold mineral interests and related assets in the Wattenberg Field for approximately $223.7 million. We paid $174.6 million in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the date of closing, for the acquired assets. The acquisition had an effective date of June 1, 2014 and allowed us to leverage our current infrastructure and technical expertise within the Rocky Mountain region. Please see Note 3 - Acquisitions above for additional discussion.

 

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see Item 3. Quantitative and Qualitative Disclosures About Market Risks below and Note 10 -  Derivatives above for additional discussion.

 

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

 

 

 

 

Cash flows provided by operating activities

 

During the nine month period ended September 30, 2014, we generated $276.0  million of cash provided by operating activities, an increase of $84.8 million from the comparable period in 2013. The increase in cash flows from operating activities resulted primarily from a 57% increase in production. The increase in production was partially offset by increased lease operating expenses, production taxes, cash portion of general and administrative expense, and cash portion of interest expense during the nine month period ended September 30, 2014 as compared to the nine month period ended September 30, 2013. See Results of Continuing Operations above for more information on the factors driving these changes.

 

Cash flows used in investing activities

 

Expenditures for development of oil and natural gas properties and natural gas plants are the primary use of our capital resources. Net cash used in investing activities for the nine months ended September 30, 2014 increased $303.8 million inclusive of $6.0 million in proceeds received from the sale of the Midway Sunset property, compared to the same period in 2013. For the nine months ended September 30, 2014, cash used for the acquisition of oil and gas properties was $178.9 million and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $448.9 million. For the nine months ended September 30, 2013, cash used for the acquisition of oil and gas properties was $11.0 million and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $311.1 million.

 

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Cash flows provided by financing activities

 

Net cash provided by financing activities for the nine months ended September 30, 2014 increased $117.9 million, compared to the same period in 2013. The increase is primarily due to the decrease in net repayments on our revolving credit facility of $119.5 million for the nine months ended September 30, 2014 when compared to the same period in 2013.

 

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 Item 7 of our 2013 Form 10-K.

 

Effects of Inflation and Pricing

 

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three and nine month periods ended September 30, 2014 and 2013. Although the impact of inflation has been 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, 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. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

 

Off-Balance Sheet Arrangements

 

Currently, we do not have any off-balance sheet arrangements.

 

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. 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:

 

 

 

 

 

 

 

 

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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:

 

 

 

 

 

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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 cause our actual results to differ materially from our expectations under Part II, Item 1A, Risk Factors, and Part I, 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.

 

 

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Item 3.Quantitative and Qualitative Disclosures About Market Risk.

 

Oil and Natural Gas Prices

 

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, 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, the strength of the U.S. dollar compared to other currencies, 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 commodity derivative contracts for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with counterparties who we believe are well-capitalized counterparties and who 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 and natural gas or otherwise fail to perform. In addition, to the extent that we engage in hedging activities, 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 five counterparties, all of which are lenders under our revolving credit facility. If a counterparty fails to perform its 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 or collar ceilings requires us to make payment for the settlement of our hedge 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 10 — Derivatives in Part I, Item 1of this Report for a summary derivative activity table.

 

Interest Rates

 

As of September 30, 2014, and on the filing date of this Report, we had no outstanding borrowings under our revolving credit facility, which is subject to floating market rates of interest. Borrowings under our revolving credit facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow.

 

Customer Credit Risk

 

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.

 

Marketability of Our Production

 

The marketability of our production from the Mid-Continent and Rocky Mountain regions depends in part upon the availability, proximity and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas

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gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas through trucking services, pipelines and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

 

A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

 

Currently, there are no natural gas pipeline systems that service wells in the North Park Basin, which is prospective for the Niobrara shale. In addition, we are not aware of any plans to construct a facility necessary to process natural gas produced from this basin. If neither we nor a third party constructs the required pipeline system and processing facility, we may not be able to fully test or develop our resources in the North Park Basin.

 

There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our 2013 Form 10-K.

 

Item 4.Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures

 

Our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2014. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of September 30, 2014, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

 

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II—OTHER INFORMATION

 

Item 1.Legal Proceedings.

 

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other gas and oil producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there are no material pending or overtly threatened legal actions against us that of which we are aware.

 

 

Item 1A. Risk Factors.

 

Our business faces many risks. Any of the risk factors discussed in this Report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and

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uncertainties, see the information in Part I, Item 1A., Risk Factors, in our 2013 Form 10-K. There have been no material changes to our risk factors from those described in our 2013 Form 10-K.

 

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds.

 

Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended September 30, 2014.

 

Issuer purchases of equity securities.  The following table contains information about our acquisition of equity securities during the three month period ended September 30, 2014.

 

 

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A dividend payment, whether it be in the form of cash, securities or other property, is restricted by our revolving credit facility and Senior Notes.

 

 

Item 3.Defaults Upon Senior Securities.

 

None.

 

Item 4.Mine Safety Disclosures.

 

Not applicable.

 

Item 5.Other Information

 

None.

 

Item 6.Exhibits.

 

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

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