Civitas Resources - 10-Q quarterly report FY2012 Q2

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

or

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to

Commission File Number:

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.  x Yes  o 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  o 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.

SEC 1296 (01-12) Potential persons who are to respond to the collection of information contained in this form are not required to respond unless the form displays a currently valid OMB control number.

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. 40,011,894 shares of common stock were outstanding as of June 30, 2012.

PART I - FINANCIAL INFORMATION

Item 1.   Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited)

See accompanying notes to these consolidated financial statements.

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

See accompanying notes to these consolidated financial statements.

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

See accompanying notes to these consolidated financial statements.

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Bonanza Creek Energy, Inc.

Notes to the Consolidated Financial Statements as of June 30, 2012 (unaudited)

1. ORGANIZATION AND BUSINESS:

On December 23, 2010, Bonanza Creek Energy, Inc., a Delaware corporation formed on December 2, 2010 (the “Company” or “BCEI”), participated in the following transactions which were accomplished simultaneously:

(1)                              The contribution by Bonanza Creek Energy Company, LLC (“BCEC”) of all of its ownership in Bonanza Creek Energy Operating Company, LLC (a wholly owned subsidiary) to BCEI and assumption by BCEI of BCEC’s remaining debt (as described below) in exchange for a 21.55% ownership interest of BCEI. BCEC had no other significant assets or subsidiaries at such time. BCEC was an operating oil and gas company that was initially founded in 2006;

(2)                                  The sale of $265 million of common stock of BCEI which constituted an ownership interest of 72.68% of BCEI to Project Black Bear LP (“Black Bear”), an entity advised by West Face Capital Inc. (“West Face Capital”), and to certain clients of Alberta Investment Management Corporation (“AIMCo”); and

(3)                                  The exchange of shares of 5.77% of BCEI’s common stock together with $59 million in cash (which came from the $265 million sale of common stock of BCEI described in (2) above), for all of the equity interests of Holmes Eastern Company, LLC, a Delaware limited liability company (“HEC”), that was majority owned by a minority member of Bonanza Creek Oil Company, LLC (“BCOC”).  BCOC was the predecessor of BCEC and owned 29.9% of BCEC on a fully diluted basis at the time of such transaction. HEC was initially formed in 2009 and has been an operating oil and gas exploration and production business since its formation.

The BCEC ownership (21.55%) of BCEI was subsequently distributed to or for the benefit of BCEC’s members based on management’s estimate of fair value of the BCEI shares received by BCEC to holders of the equity interests of BCEC in connection with the redemption of BCEC’s equity and BCEC’s dissolution to of for the benefit of:

(1)                                  BCOC in the amount of 5.5% (for its Series A Units of BCEC);

(2)                                  D.E. Shaw Laminar Portfolios, L.L.C. (“Laminar”) in the amount of 12.91% (for its Series A Units of BCEC); and

(3)                                  The management and employees of BCEC, in the amount of 3.14% (for their Class B Units of BCEC).

Cash proceeds of approximately $182 million were used to retire BCEC’s second lien term loan, senior subordinated notes and a related party note payable, and to reduce the outstanding principal balance on BCEC’s bank revolving credit facility by $29 million thereby reducing the balance outstanding to approximately $55.4 million as of December 31, 2010. This loan at the same time was assumed by BCEI.

The Company is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of June 30, 2012, the Company’s assets and operations are concentrated primarily in southern Arkansas and in the Wattenberg field and North Park Basin in the Rocky Mountains.

2. BASIS OF PRESENTATION:

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles.  The readers of these quarterly financial statements should also read the audited consolidated financial statements and related notes of BCEI that were included in BCEI’s Annual Report on Form 10-K filed with the SEC on March 22, 2012.  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.

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Principles of Consolidation—The consolidated balance sheet includes the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, HEC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC and Liberty Energy Company, LLC.  All significant intercompany accounts and transactions have been eliminated.

Oil and Gas Producing Activities—The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs will be charged to expense. The costs of development wells will be capitalized whether productive or nonproductive. Costs incurred to maintain wells and related equipment and lease and well operating costs are charged to expense as incurred. Gains and losses arising from sales of properties will be included in income. However, sales that do not significantly affect a field’s unit-of-production depletion rate will be accounted for as normal retirements with no gain or loss recognized. Geological and geophysical costs of exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred.

Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units of production method based upon proved reserves. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage and the Company’s expected cost to abandon its well interests.

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property will be written down to “fair value.” Fair value for oil and natural gas properties is generally determined based on discounted future net cash flows.

3. DIVESTITURES:

During June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California.  In accordance with ASC Topic 360, 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 expense any excess of carrying value over fair value less costs to sell.  The Company determined that its intent to sell these properties qualifies for discontinued operations although the Company has not yet reached any definitive agreement with a counter party to sell the properties.  The carrying amounts of the major classes of assets and liabilities related to the operation of these properties that are held for sale as of June 30, 2012 and December 31, 2011 are presented below:

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Total revenues and costs and expenses, and the income associated with the operation of the oil and gas properties held for sale for the three six month periods ended June 30, 2012 and 2011 are presented below.

4. RECENT ACCOUNTING PRONOUNCEMENTS:

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”).  The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position.  ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard is not expected to have an impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement.  The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”).  The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements.  These amendments are not expected to have a significant impact on companies applying GAAP.  ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011.  The adoption of this standard did not have an impact on the Company’s consolidated financial statements other than additional disclosures.

5. ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

Accounts payable and accrued expenses contain the following:

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6. SENIOR SECURED REVOLVING CREDIT FACILITY:

Senior Secured Revolving Credit Facility—On May 8, 2012, the Company amended its senior secured revolving Credit Agreement, (the “Revolver”) dated March 29, 2011, with a syndication of banks, including KeyBank National Association as the administrative agent and issuing lender, which provides for borrowings of up to $600 million. The Revolver provides for interest rates plus an applicable margin to be determined based on the London Interbank Offered Rate (LIBOR) or a bank base rate (“Base Rate”), at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.75% to 2.75% depending on the utilization level, and the Base Rate borrowings bear interest at the “Bank Prime Rate,” as defined plus .75% to 1.75%.

The Revolver had a $245 million borrowing base as of June 30, 2012 and is subject to semi-annual re-determinations in April and October of each year. The Revolver provides for commitment fees ranging from 0.375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans, and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of a minimum current ratio and a minimum debt coverage ratio, as defined. The Company was in compliance with these covenants as of June 30, 2012. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2016.

7. COMMITMENTS AND CONTINGENT LIABILITIES:

Office Leases—The Company rents office facilities under various noncancelable operating lease agreements.  The Company’s noncancelable operating lease agreements result in total future minimum noncancelable lease payments are presented below.  The Company also has principal payment requirements for its line of credit which is also presented below:

Environmental—The Company is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures related to the drilling of oil and gas wells and the operations. Relative to the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up or restoration, the liability to cure such a violation could fall upon the Company. Management believes its properties are operated in conformity with local, state and federal regulations. No claim has been made, nor is the Company aware of any uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations.

Legal Proceedings—The Company may from time to time be involved in various legal actions arising in the normal course of business. During the second quarter of 2011, its Board of Directors formed a Special Litigation Committee comprised of three non-executive directors to investigate the merits of a demand for arbitration against its current President and Chief Executive Officer from the former Chairman of BCEC related to the management of BCOC and BCEC primarily during the 2005-2006 time period. These demands do not allege any wrongdoing by or claims against the Company. The Special Litigation Committee retained outside independent advisors to conduct the investigation and concluded that the allegations lack merit.  An arbitration hearing commenced in July 2012 and it is not clear when a final decision will be rendered.  Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims.  During the period from January 1, 2012 through June 30, 2012 the Company incurred approximately $1.2 million related to Mr. Bennett’s claims.

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8. FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

The Company follows FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. 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:

ASC 820 requires financial assets and liabilities 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 table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 by level within the fair value hierarchy:

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 by level within the fair value hierarchy:

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  All valuations were compared against counterparty statements to verify the reasonableness of the estimate.  The Company’s commodity swaps are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The Company’s collars, which are designated as Level 3 within the valuation hierarchy, are not validated by observable transactions with respect to volatility. The counterparties in all of the commodity derivative financial instruments are lenders on the Company’s senior secured revolving credit facility.

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs during the period from January 1, 2012 through June 30, 2012:

As of June 30, 2012, the Company’s derivative commodity contracts:

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The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of June 30, 2012:

Realized gains and losses on commodity derivatives and the unrealized gains or losses are recorded in other income (expense).

Asset Retirement Obligation—Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions.

9. STOCKHOLDERS’ EQUITY:

Management Incentive Plan—On December 23, 2010, the Company established the Management Incentive Plan (the “Plan” or “MIP”) for the benefit of certain employees, officers and other individuals performing services for the Company. 10,000 shares of Class B common stock were available under the Plan and these shares were converted into 437,787 shares of restricted common stock upon completion of its initial public offering. The conversion rate was determined based on a formula factoring in the rate of return to the common stockholders. The 437,787 shares of common stock that were granted to employees were valued at $17.00 per share on the grant date and vest over a three year period. Non-cash compensation expense of approximately $1,223,000 was recorded during the six months ended June 30, 2012 and there was approximately $6,019,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the plan. That cost is expected to be recognized over a period of 2.5 years.

BCEC Management Incentive Plan—As of June 30, 2012, 73,197 shares of BCEI common stock remain held in trust and designated for holders of BCEC’s Class B units. When and if such shares are issued, they will be valued based on the market price of the Company’s common stock on the grant date.

On June 14, 2012, the Company granted 540,000 shares of restricted common stock under its 2011 Long Term Incentive Plan to officers and certain employees.  For accounting purposes, these shares were valued at $15.38, the closing price of its common stock on the grant date.  These shares will vest annually in one-third increments over approximately 2.7 years and will be fully vested in February of 2015.

10. 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.

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 follows the provisions of FASB ASC 740, Accounting for Uncertainty in Income Taxes. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company files income tax returns in the U.S. federal jurisdiction and various states. The Company has not taken any uncertain tax positions.

11. SUBSEQUENT EVENTS:

On July 31, 2012, the Company acquired leases to approximately 5,600 net acres in the Wattenberg field from the State of Colorado, State Board of Land Commissioners for approximately $60,000,000.  The Company paid approximately $12 million at closing and will pay approximately $12 million on July 31st of each of the next four years.  These future payments are secured by a letter of credit.

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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, 2011 (the “2011 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (this “Report”).

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. These forward-looking statements may include projections and estimates concerning our capital expenditures, our liquidity and capital resources, our estimated revenues and losses, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, our business strategy and other statements concerning our operations, economic performance and financial condition. When used in this Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. 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. 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.

Forward-looking statements may include statements about:

·                  our ability to replace oil and natural gas reserves;

·                  declines or volatility in the prices we receive for our oil and natural gas;

·                  our financial position;

·                  our cash flow and liquidity;

·                  general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

·                  the recent economic slowdown that has and may continue to adversely affect consumption of oil and natural gas by businesses and consumers;

·                  our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;

·                  the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

·                  uncertainties associated with estimates of proved oil and gas reserves and, in particular, probable and possible resources;

·                  the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulation);

·                  environmental risks;

·                  drilling and operating risks;

·                  exploration and development risks;

·                  competition in the oil and natural gas industry;

·                  management’s ability to execute our plans to meet our goals;

·                  our ability to retain key members of our senior management and key technical employees;

·                  access to adequate gathering systems and pipeline take-away capacity to execute our drilling program;

·                  our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

·                  costs associated with perfecting title for mineral rights in some of our properties;

·                  continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

·                  other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing.

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

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that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations below and under “Item 1A. Risk Factors” in our 2011 Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States.  Our assets and operations are concentrated primarily in southern Arkansas (Mid-Continent region) and the Wattenberg Field and North Park Basins in Colorado (Rocky Mountain region).  In addition, we own and operate oil producing assets in the San Joaquin Basin (California region), which are currently classified as discontinued operations.  Our management team has extensive experience acquiring and operating oil and gas properties, which we believe will contribute to the development of our inventory of projects, including those targeting the oily Cotton Valley sands in our Mid-Continent region and the Niobrara oil shale formation in our Rocky Mountain region.  We operate approximately 99.5% and hold an average working interest of approximately 80.7% of our proved reserves, providing us with significant control over the rate of development of our asset base.

As demonstrated by our $165.5 million capital program in 2011 and our recently amended $298 million capital program for 2012, we are increasingly focused on exploiting our inventory of high-return locations.  We also continue to seek acquisitions that will complement our existing core properties.

Our revenue, profitability and future growth rate depend on factors beyond our control, such as economic, political and regulatory developments.  Oil and gas prices historically have been volatile and may fluctuate widely in the future.  We attempt to protect our capital and operational plans by judiciously hedging our sales of oil and natural gas.

Second Quarter 2012 Highlights:

For the second quarter 2012,

·                  Total production was 793 MBoe (8,717 Boe/d average daily production), a 150% increase over the second quarter 2011 and 26% over the first quarter 2012;

·                  Total revenue was $51.5 million, a 113% increase over the second quarter 2011 and 8% over the first quarter 2012; and

·                  Net income was $21.2 million, or $0.53 per diluted share.

Results for Continuing Operations

Three Months Ended June 30, 2012 Compared To Three Months Ended June 30, 2011

Revenues

The following table summarizes our revenues and production data for the periods indicated.

(1) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.  Excludes CO2 sales.

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(1)  Although we do not designate our derivatives as cash flow hedges for financial statement purposes, the derivatives do economically hedge the price we receive for crude oil and natural gas.

(2)  Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.  Excludes CO2 sales.

Revenues increased by 113%, to $51.5 million for the three months ended June 30, 2012 compared to $24.2 million for the three months ended June 30, 2011.  Oil, natural gas, and natural gas liquids production increased 161%, 158%, and 80%, respectively, during the three months ended June 30, 2012, as compared to the three months ended June 30, 2011.  During the period from June 30, 2011 through June 30, 2012, we drilled and completed 97 gross (91.9 net) wells in the Rockies and 49 gross (42.5 net) wells in Southern Arkansas.  The increased volumes are a direct result of the $165.5 million expended for drilling and completion during the year ended December 31, 2011, and the $149.6 million expended during the six months ended June 30, 2012.  Oil prices decreased from an average of $96.78 in 2011 to a per barrel rate of $89.47 in the comparable three month period that ended June 30, 2012.  Increased oil volumes of 161% accounted for $25.7 million of the total $27.3 million increase in revenues for the Company for the three month period ended June 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 158% in 2012, but were offset by a sales price decline of 40% from $5.06 per Mcf to $3.05 per Mcf for these three month periods. Natural gas liquids volumes increased by 80% in 2012, but were offset by a sales price decline of 41% from $80.30 per barrel to $47.03 per barrel for these three month periods.  Our Wattenberg field natural gas is sold without processing and sells at a premium due to its very high BTU content.  Our production of oil, natural gas, and natural gas liquids for the three months ended June 30, 2012 was approximately 62%, 30% and 8%, respectively.

Operating Expenses

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

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Lease Operating Expense.  Our lease operating expenses increased $3.3 million, or 89%, to $7.0 million for the three months ended June 30, 2012 from $3.7 million for the three months ended June 30, 2011 and decreased on an equivalent basis from $11.62 per Boe to $8.77 per Boe.  The increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2011, but not operational during the three months ended June 30, 2011.  Gas plant operating expense, which is a component of lease operating expense, increased $0.6 million, or 36%, to $2.1 million for the three month period ended June 30, 2012 from $1.5 million for the three month period ended June 30, 2011.  Significant increases in gas plant operating expenses period over period were for compression and rental equipment and repairs and maintenance which were $0.3 million and $0.2 million, respectively.  During the three months ended June 30, 2012, well servicing, rental equipment, and other expenses were $1.8 million, $0.2 million, and $0.2 million higher, respectively, than the three months ended June 30, 2011.  The decrease in lease operating expense on an equivalent basis was primarily related to the lower per unit operating costs of the wells drilled during the period from June 30, 2011 through June 30, 2012.

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $1.4 million, or 98%, to $2.8 million for the three months ended June 30, 2012 from $1.4 million for the three months ended June 30, 2011.  The increase was primarily related to a 150% increase in production volumes partially offset by a 14% decrease in realized prices per Boe during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011.  The increase in severance and ad valorem taxes for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011 was related to oil severance taxes and ad valorem taxes that were $0.4 million and $1.0 million, respectively, higher than the comparable period in the previous year.

Exploration costs.  Our exploration expense increased $2.0 million, or 8,661%, to $2.0 million in the three months ended June 30, 2012 from $23 thousand in the three months ended June 30, 2011.  During the three months ended June 30, 2012, a seismic acquisition project in the North Park Basin of Colorado was reprocessed which resulted in charges of approximately $0.5 million. One exploratory location where surface casing had been set and minimal work performed was also charged to exploration expense because the work had been performed during 2010 and management had no current plans to complete a well on this location.  This resulted in a $1.5 million non-cash charge to our statement of operations during the three months ended June 30, 2012.

Depletion, depreciation and amortization.  Our depletion, depreciation and amortization expense increased $6.4 million, or 97%, to $13.0 million for the three months ended June 30, 2012 from $6.6 million for the three months ended June 30, 2011.  This increase was the result of a 150% increase in production period over period.  Our depreciation, depletion and amortization expense per Boe produced decreased $4.49, or 21% to $16.43 for the three months ended June 30, 2012 as compared to $20.92 for the three months ended June 30, 2011.  This decrease to depreciation, depletion and amortization expense per Boe resulted from additions to the proved developed reserve base from accretive drilling during the period from July 1, 2011 through June 30, 2012.

General and administrative. Our general and administrative expense increased $4.4 million, or 164%, to $7.1 million for the three months ended June 30, 2012 from $2.7 million for the period ended June 30, 2011. During the three months ended June 30, 2012, wages, benefits and employee placement fees were $2.5 million higher than the three month period ended June 30, 2011 due to our headcount increasing by approximately 50 employees, or 69% period over period, as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced.  During the three months ended June 30, 2012, legal fees were $0.9 million higher, software maintenance was $0.1 million higher and non-cash stock compensation charges for officers and certain employees were $0.7 million higher than the three month period ended June 30, 2011.  The majority of the increased general and administrative expense is due to hiring a large number of personnel to support our growth and the regulatory compliance obligations of a newly public company.

Interest expense.  Our interest expense decreased $0.2 million, or 23%, to $0.7 million for the three months ended June 30, 2012 from $0.9 million for the three months ended June 30, 2011.  The decrease resulted from a decrease in the average debt outstanding for the three months ended June 30, 2012 compared to the three months ended June 30, 2011.  Average debt outstanding for the three months ended June 30, 2012 was $44.7 million as compared to $74.0 million for the three month ended June 30, 2011.

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities decreased by $1.2 million from a loss of $1.1 million for the three months ended June 30, 2011 to a gain of $0.1 million for the three months ended June 30, 2012.  The change from a realized loss to a realized gain period over period was primarily related to commodity prices that were 14% lower during the three month period ended June 30, 2012.  Hedging gains for the month of June were $0.8 million as the NYMEX sweet

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crude oil price averaged $82.41 during June of 2012 as compared to our oil hedges which had an average floor of $88.61 per barrel during June of 2012.

Income tax expense.  Our estimate for federal and state income taxes for the three months ended June 30, 2012 was $13.3 million from continuing operations as compared to $4.4 million for the three months ended June 30, 2011.  We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation.  All income taxes for the periods ended June 30, 2012 and 2011 were deferred.  Our effective tax rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

Six Months Ended June 30, 2012 Compared To Six Months Ended June 30, 2011

Revenues

The following table summarizes our revenues and production data for the periods indicated.

(1) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.  Excludes CO2 sales.

(1)  Although we do not designate our derivatives as cash flow hedges for financial statement purposes, the derivatives do economically hedge the price we receive for crude oil and natural gas.

(2)  Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.  Excludes CO2 sales.

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Revenues increased by 122%, to $99.3 million for the six months ended June 30, 2012 compared to $44.7 million for the six months ended June 30, 2011.  Oil, natural gas, and natural gas liquids production increased 151%, 109%, and 63%, respectively, during the six months ended June 30, 2012, as compared to the six months ended June 30, 2011.  During the period from June 30, 2011 through June 30, 2012, we drilled and completed 97 gross (91.9 net) wells in the Rockies and 49 gross (42.5 net) wells in Southern Arkansas. The increased volumes are a direct result of the $165.5 million expended for drilling and completion during the year ended December 31, 2011, and the $149.8 million expended during the six months ended June 30, 2012.  Oil prices increased from an average of $92.81 in 2011 to a per barrel rate of $93.93 in the comparable six month period that ended June 30, 2012.  The combination of increased oil volumes and prices accounted for $51.0 million of the total $54.6 million increase in revenues for the Company for the six month period ended June 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 109% in 2012, but were offset by a sales price decline of 36% from $5.06 per Mcf to $3.22 per Mcf for these six month periods.  Natural gas liquid volumes increased by 63% in 2012, but were offset by a salesprices decline of 18% from $68.08 per Bbl to $55.66 per Bbl for these six month periods.  Our Wattenberg field natural gas is sold without processing and sells at a premium due to its very high BTU content.  Our production of oil, natural gas, and natural gas liquids for the six months ended June 30, 2012 was approximately 63%, 27% and 10%, respectively.

Operating Expenses

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

Lease Operating Expense.  Our lease operating expenses increased $6.7 million, or 91%, to $14.1 million for the six months ended June 30, 2012 from $7.4 million for the six months ended June 30, 2011 and decreased on an equivalent basis from $11.71 per Boe to $9.88 per Boe.  The increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2011, but not operational during the six months ended June 30, 2011.  Gas plant operating expense, which is a component of lease operating expense, increased $1.4 million, or 55%, to $4.0 million for the six month period ended June 30, 2012 from $2.6 million for the six month period ended June 30, 2011.  Significant increases in gas plant operating expenses period over period were for compression and rental equipment, repairs and maintenance, and utilities and electrical which were $0.8 million, $0.4 million, and $0.3 million, respectively.  During the six months ended June 30, 2012, well servicing, rental equipment, pumping and gauging, and other expenses were $2.9 million, $0.4 million, $0.3 million and $0.3 million higher, respectively, than the six months ended June 30, 2011.  The decrease in lease operating expense on an equivalent basis was primarily related to accretive drilling and the lower per unit operating costs of the wells drilled during the period from June 30, 2011 through June 30, 2012.

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $4.0 million, or 161%, to $6.4 million for the six months ended June 30, 2012 from $2.4 million for the six months ended June 30, 2011.  The increase was primarily related to a 127% increase in production volumes partially offset and a 2% decrease in realized prices per Boe during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011.  The increase in severance and ad valorem taxes on a Boe basis for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011 was related to oil severance taxes and ad valorem taxes that were $2.5 million and $1.2 million, respectively, higher than the comparable period in the previous year.

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Exploration costs.  Our exploration expense increased $2.7 million, or 485%, to $3.2 million in the six months ended June 30, 2012 from $0.5 million in the six months ended June 30, 2011.  During the six months ended June 30, 2012, a seismic acquisition project was conducted in the North Park Basin of Colorado to assist the scientific staff in identifying the appropriate drill locations and plans for future development.  This survey was reprocessed during the second quarter which resulted in additional charges of approximately $0.5 million. In addition to the seismic survey, one exploratory location where surface casing had been set and minimal work performed was charged to exploration expense because the work had been performed during 2010 and management had no current plans to complete a well on this location.  This resulted in a $1.5 million non-cash charge to our statement of operations during the six months ended June 30, 2012. During the six months ended June 30, 2011, we acquired 7,700 acres of 3-D seismic data on the eastern edge of the Wattenberg field in Weld County Colorado to help evaluate our Niobrara oil shale acreage.

Depletion, depreciation and amortization.  Our depletion, depreciation and amortization expense increased $11.9 million, or 96%, to $24.0 million for the six months ended June 30, 2012 from $12.1 million for the six months ended June 30, 2011.  This increase was the result of a 127% increase in production period over period.  Our depreciation, depletion and amortization expense per Boe produced decreased $2.44, or 13% to $16.89 for the six months ended June 30, 2012 as compared to $19.33 for the six months ended June 30, 2011.  This decrease to depreciation, depletion and amortization expense per Boe resulted from additions to the proved developed reserve base from accretive drilling during the period from July 1, 2011 through June 30, 2012.

General and administrative. Our general and administrative expense increased $8.1 million, or 165%, to $13.1 million for the six months ended June 30, 2012 from $5.0 million for the six months ended June 30, 2011. During the six months ended June 30, 2012, wages, benefits and employee placement fees were $4.9 million higher than the six month period ended June 30, 2011 due to our headcount increasing by approximately 50 employees, or 74% period over period, as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced. During the six months ended June 30, 2012, accounting fees were $0.4 million higher due to a one-time payment that was made to our outsource accounting provider to terminate our agreement with them. Also during the six months ended June 30, 2012, legal fees were $1.0 million higher, franchise taxes were $0.3 million higher and non-cash stock compensation charges for officers and certain employees were $1.4 million higher than the six month period ended June 30, 2011. The majority of the increased general and administrative expense is due to hiring a large number of personnel to support our growth and the regulatory compliance obligations of a newly public company.

Interest expense.  Our interest expense decreased $0.4 million, or 22%, to $1.2 million for the six months ended June 30, 2012 from $1.6 million for the six months ended June 30, 2011.  The decrease resulted from a decrease in the average debt outstanding for the six months ended June 30, 2012 compared to the six months ended June 30, 2011.  Average debt outstanding for the six months ended June 30, 2012 was $29.9 million as compared to $67.7 million for the six months ended June 30, 2011.

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities decreased by $0.7 million from a loss of $1.8 million for the six months ended June 30, 2011 to a loss of $1.1 million for the six months ended June 30, 2012.  The decrease in the realized loss period over period was primarily related to hedging gains for the month of June which were $0.8 million as the NYMEX sweet crude oil price averaged $82.41 per barrel during June of 2012 as compared to our oil hedges which had an average floor of $88.61 per barrel during June of 2012.

Income tax expense.  Our estimate for federal and state income taxes for continuing operations for the six months ended June 30, 2012 was $18.6 million as compared to $4.6 million for the six months ended June 30, 2011.  We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation.  All income taxes for the periods ended June 30, 2012 and 2011 were deferred.  Our effective tax rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

Results for Discontinued Operations

During June of 2012, the Company began marketing, with an intent to sell, all of our 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 sell these properties qualifies for discontinued operations accounting and these assets will be presented as discontinued operations in the Company’s statements of operations.

The operating results before income taxes for our California properties for the three month period ended June 30, 2012 were net revenues, operating expenses, and income from discontinued operations of $2.0 million, $1.5 million and $0.5 million, respectively, as compared to net revenues, operating expenses, and income from discontinued operations of $1.8 million, $1.5 million, and $0.3 million for the three month period ended June 30, 2011.  Sales volumes for the three month periods ended June 30, 2012 and 2011 were 20.6 MBbls and 16.3 MBbls, respectively.

The operating results before income taxes for our California properties for the six month period ended June 30, 2012 were net revenues, operating expenses, and income from discontinued operations of $3.7 million, $3.1 million and $0.6 million, respectively, as compared to net

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revenues, operating expenses, and income from discontinued operations of $3.5 million, $3.4 million, and $0.1 million for the six month period ended June 30, 2011.  Sales volumes for the six month periods ended June 30, 2012 and 2011 were 36.6 MBbls and 34.7 MBbls, respectively.

Liquidity and Capital Resources

Our primary source of liquidity to date has been proceeds from our initial public offering, borrowings under our revolving credit facility and cash flows from operations.  Our primary use of capital has been the development and exploitation of our oil and gas properties.  We continually monitor potential capital sources in order to adequately plan for the growth of the Company and our planned capital expenditures and liquidity requirements.  Our future success in building and growing the Company’s reserves and production will be significantly dependent upon management’s ability to access outside sources of capital.

On December 15, 2011, the Company sold 10,000,000 shares of our common stock in our initial public offering at $17.00 per share, less $1.105 per share for underwriting discounts and commissions.  Other expenses related to the issuance and distribution of these shares were approximately $3 million.

On April 6, 2012, the administrative agent under our credit facility was changed to KeyBank, National Association.  On May 8, 2012, we entered into an amendment with the lenders under our credit facility to, among other things, (i) increase our credit facility to $600 million and borrowing base to $245 million, and (ii) make changes in the covenant applicable to hedging to allow greater flexibility for management to implement comprehensive hedging plans to adequately protect the Company’s operations and capital budgets.  As of June 30, 2012, we had $62.6 million outstanding and $182.4 million of borrowing capacity available under our credit facility.

On July 31, 2012, the Company acquired leases in the Wattenberg field from the State of Colorado, State Board of Land Commissioners for approximately $60,000,000.  The company paid approximately $12 million at closing and will pay approximately $12 million on July 31st of each of the next four years.  These future payments are secured by a letter of credit which reduced our availability under the borrowing base.

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.

We are of the opinion that we have adequate liquidity to manage our capital and business plans for the next 12 months and the foreseeable future.  In addition, we believe that the combination of our cash flow from operating activities, potential access to debt and capital markets and our current liquidity level will allow us the flexibility to modify our future capital expenditure programs and comply with all of our debt covenants, and meet all of our obligations that may arise from our ongoing operations.

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

Cash flows provided by operating activities

Cash flows derived from operating activities depend on many factors, including the price for oil and gas and our success in exploiting and exploring our oil and gas properties which ultimately leads to the volumes produced.  Costs to produce the oil and gas, our ability to contain such costs, and the severance and ad valorem taxes associated with the ownership and production of oil and gas wells have a significant impact on our profitability and cash flow from our oil and gas properties.

Net cash provided by operating activities was $56.4 million for the six months ended June 30, 2012, compared to $21.8 million provided by operating activities for the six months ended June 30, 2011.  The increase in operating activities results primarily

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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 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 affect 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.  If oil prices decline by $10.00 per Bbl, then our PV-10 as of December 31, 2011 would have been lower by approximately $129.4 million.

Our primary commodity risk management objective is to reduce volatility in our cash flows.  Management makes recommendations on hedging that are approved by the board of directors before implementation.  We enter into hedges for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties 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 natural gas or otherwise fail to perform. 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 hedging arrangements are concentrated with three counterparties, all of which are lenders under our credit facility.  If this 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 three 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 hedge settlement and payment for revenues earned.

The following table provides a summary of derivative contracts as of June 30, 2012.

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 June 30, 2012.  The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that

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