UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the Quarterly Period Ended September 30, 2015

Or

Commission File No. 001-35049  

 

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

1400 Woodloch Forest Drive, Suite 300

The Woodlands, Texas 77380

(Address of principal executive offices)

Registrant’s telephone number, including area code:  (281) 298-4246

 

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days.    Yes  þ    No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to post such filed).     Yes  þ    No  o

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 definition 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  o    No  þ

As of November 6, 2015, 13,835,128 shares of common stock, $0.001 par value per share, were outstanding.

 

 

 

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TABLE OF CONTENTS

 

 

 

 

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts contained in this report are forward-looking statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” “could,” “should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals or prospects are also forward-looking statements. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section included in our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2014, and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

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All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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PART I. FINANCIAL INFORMATION

 

 

Item 1. Financial Statements (unaudited)

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

 

 

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

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EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

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

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EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

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

 

 

 

 

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

 

Note 1. Basis of Presentation

Earthstone Energy, Inc., a Delaware corporation (“Earthstone” or the “Company”) is an independent oil and gas exploration and production company engaged in the acquisition, development, exploration and production of onshore, unconventional reserves, with a current focus on the Eagle Ford trend of South Texas and the Bakken trend of North Dakota and Montana. The Company also has conventional wells in East Texas, South Texas and Oklahoma.

The accompanying unaudited consolidated financial statements of Earthstone and our wholly-owned subsidiaries, which we refer to as “we,” “our” or “us,” have been prepared in accordance with Article 8-03 of Regulation S-X for interim financial statements required to be filed with the Securities and Exchange Commission (“SEC”).  The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company's Condensed Consolidated Balance Sheets as of September 30, 2015, and December 31, 2014; the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014; and the Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014.  The Company’s balance sheet at December 31, 2014 is derived from the audited consolidated financial statements at that date.

The preparation of financial statements in conformity with the generally accepted accounting principles of the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. For further information, see Note 2 in the Notes to Consolidated Financial Statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014.

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements and the accompanying notes prepared in accordance with GAAP, has been condensed or omitted. These financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and the Company’s other filings with the SEC.  The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

On December 19, 2014, the Company acquired three operating subsidiaries of Oak Valley Resources, LLC (“OVR”), in exchange for shares of Earthstone common stock (the “Exchange”), which resulted in a change of control of the Company. Pursuant to the Exchange Agreement, OVR contributed to Earthstone the membership interests of its three subsidiaries, Oak Valley Operating, LLC (“OVO”), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”), in exchange for approximately 9.124 million shares, representing 84% of the Company’s common stock.  The transaction was accounted for as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes.  All historical financial information, prior to December 19, 2014, contained in this Quarterly Report on Form 10-Q is that of Oak Valley.

Immediately following the Exchange, the Company, through its acquired wholly owned subsidiary, Sabine, acquired an additional 20% undivided ownership interest in certain crude oil and gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of approximately 2.957 million shares of common stock (the “Contribution Agreement”) to Flatonia Energy, LLC, increasing the Company’s ownership in these properties from a 30% undivided ownership to a 50% undivided ownership interest.  As a result of the share issuance to Flatonia, OVR’s ownership in the Company decreased from 84% to 66%.

Recently Issued Accounting Standards

Revenue Recognition - In May 2014, the Financial Accounting Standards Board (“FASB”) issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods after December 15, 2017; early adoption is permitted as of the original effective date of December 31, 2016. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its consolidated financial statements.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in the financial statements.  Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset.  Amortization of the costs is reported as interest expense.  In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset.  The standards update is effective for interim and annual periods beginning after December 15, 2015.  The Company will adopt this standards update, as required, beginning with the first quarter of 2016 and it will be retrospectively applied to all prior periods.  The Company does not expect the adoption of this new presentation guidance to have a material impact on its consolidated balance sheets.

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination.  The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.  The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015 with early adoption permitted.  The Company will adopt this standard update, as required, beginning with the first quarter of 2016, and does not expect it to have a material impact on its consolidated financial statements.  

 

 

Note 2. Acquisitions and Divestitures

Earthstone Energy Reverse Acquisition

On December 19, 2014, the Company and OVR closed the Exchange. In this transaction, OVR contributed to the Company the membership interests of its three wholly-owned subsidiaries, which included producing assets, undeveloped acreage and cash.  OVR received approximately 9.124 million shares of newly issued common stock, $0.001 par value per share (the “Common Stock”), of the Company. The Exchange resulted in a change of control of the Company. The Exchange has been accounted in accordance with FASB Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC 805”) as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes although Earthstone is the acquirer for legal purposes. ASC 805 also requires, that among other things, assets acquired and liabilities assumed to be measured at their acquisition date fair values. The results of operations from Earthstone’s legacy assets are reflected in the Company’s consolidated statement of operations beginning December 19, 2014.

An allocation of the purchase price was prepared using, among other things, the 2014 year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. that was adjusted and re-priced by the Company’s reserve engineering staff back to the December 19, 2014 acquisition date. The following allocation is still preliminary with respect to final tax amounts, pending the completion of the 2014 Earthstone tax return and certain accruals and includes the use of estimates based on information that was available to management at the time these consolidated financial statements were prepared. Additional changes to the purchase price allocation may result in a corresponding change to goodwill in the period of the change.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

The following table summarizes the consideration paid to acquire the legacy Earthstone net assets and the estimated values of those net assets (in thousands, except share and share price amounts):

 

 

2014 Eagle Ford Acquisition Properties

Also on December 19, 2014, immediately following the Exchange, Flatonia Energy, LLC (“Flatonia”), Parallel Resource Partners, LLC (“Parallel”), and Sabine, closed the transactions contemplated by the Contribution Agreement by and among the Company, OVR, Sabine, Oak Valley Operating, LLC, Parallel, and Flatonia, whereby Parallel contributed 28.57% of the oil and natural gas property interests held by Flatonia, a wholly owned subsidiary of Parallel, in consideration for approximately 2.96 million shares of Common Stock (the “Contribution”). The assets subject to the Contribution Agreement were oil and natural gas property interests in producing wells and acreage in the Eagle Ford trend of Texas (the “2014 Eagle Ford Acquisition Properties”). One of the subsidiaries included in the Exchange is the operator of the 2014 Eagle Ford Acquisition Properties. The only relationship that Flatonia or Parallel

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

had with this subsidiary or the Company prior to the transaction was that the subsidiary is the operator of the 2014 Eagle Ford Acquisition Properties. The Contribution was accounted for as a business combination in accordance ASC 805 which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date. 

An allocation of the purchase price was prepared using, the 2014 year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. that was adjusted and re-priced by the Company’s reserve engineering staff back to December 19, 2014. The following allocation is still preliminary with respect to final tax amounts, pending the completion of the 2014 Flatonia tax return and certain accruals and it includes the use of estimates based on information that was available to management at the time these consolidated financial statements were prepared. The Company’s final allocation of purchase price is dependent on the seller’s tax return since Earthstone received carryover basis on Flatonia’s assets and liabilities because the Contribution Agreement was not a taxable transaction under the United States Internal Revenue Code of 1986, as amended. Additional changes to the purchase price allocation may result in a corresponding change to goodwill in the period of the change.

The following table summarizes the consideration paid to acquire the 2014 Eagle Ford Acquisition Properties and the estimated values of those net assets (in thousands, except share and share price amounts):

 

 

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

The following unaudited supplemental pro forma combined condensed results of operations present consolidated information as though the Exchange and Contribution had been completed as of January 1, 2014. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Exchange or Contribution or any estimated costs that will be incurred to integrate the legacy Earthstone net assets and the 2014 Eagle Ford Acquisition Properties. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts).

 

 

For the three and nine months ended September 30, 2015, the Company recognized $2.0 million and $7.3 million, respectively, of oil, natural gas and natural gas liquids sales related to the legacy Earthstone assets and operating expenses including depletion of $2.5 million and $8.4 million, respectively. There were no material non-recurring transaction costs related to this acquisition incurred during the three and nine months ended September 30, 2015.

For the three and nine months ended September 30, 2015, the Company recognized $3.2 million and $9.8 million, respectively, of oil, natural gas and natural gas liquids related to the 2014 Eagle Ford Acquisition Properties and operating expenses including depletion of $2.5 million and $7.9 million, respectively. There were no material non-recurring transaction costs related to this acquisition incurred during the three and nine months ended September 30, 2015.

Other Acquisitions

In June 2015, the Company acquired a 50% operated interest in two gross Austin Chalk wells, which hold approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production, with current gross production of 44 barrels of oil equivalent per day (“BOEPD”) all of which was oil.  Also during June 2015, the Company acquired additional acreage in northern Karnes County, Texas, increasing its total leasehold position to approximately 400 gross acres.  The Company currently has a 33% working interest in the Karnes acreage.  These two positions are adjacent to one another and will provide for 17 gross Eagle Ford locations with expected development beginning in the fourth quarter of 2015.

The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands):

 

 

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Pro forma financial information, assuming the acquisition occurred at the beginning of each period presented, has not been presented because the effect on the Company’s results for each of those periods is not material.  The results of the above acquisitions have been included in the Company’s consolidated financials since the date of each acquisition.

In June 2015, the Company acquired additional acreage and increased the Company’s working interest in wells in existing Bakken spacing units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.1 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells.  The acquisition included 164 net acres which allowed the Company to increase its working interest in approximately 41 producing wells and 21 wells that are in the drilling and completion phase.

In August 2015, the Company acquired a 33% working interest in approximately 1,650 gross acres, in Southern Gonzales County, Texas for $3.3 million. This acreage supports 16 additional gross Eagle Ford locations.  

Divestitures

In April 2015, the Company sold its Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million.  The Company recorded a gain of $1.7 million on the sale.  The effective date of the transaction was March 1, 2015.

 

 

Note 3. Derivative Financial Instruments

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815 Derivatives and Hedging (“ASC Topic 815”), to account for its derivative financial instruments. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The counterparties to the Company’s current derivative contracts are lenders in the Company’s credit agreement, which is described in Note 6 Long-Term Debt below. The Company did not post collateral under any of these contracts as they are secured under the Company’s credit agreement with the same counterparties.

The Company’s crude oil and natural gas derivative positions are swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain on derivative contracts” on the Condensed Consolidated Statements of Operations. All derivative contracts are recorded at their fair market value and are included in the Company’s Condensed Consolidated Balance Sheets as assets or liabilities.

With an individual derivative counterparty, the Company may have multiple hedge positions that expire at various points in the future and result in fair value asset and liability positions. At the end of each reporting period, those positions are offset to a single fair value asset or liability for each commodity per counter party, and the netted balance is reflected in the Company’s Consolidated Balance Sheets as an asset or a liability.

The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

The Company had the following open crude oil derivative contracts as of September 30, 2015:

 

 

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

 

The following table summarizes the location and fair value amounts of all derivative instruments in the Condensed Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Condensed Consolidated Balance Sheets (in thousands):

 

 

The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative instruments in the Company’s Condensed Consolidated Statements of Operations (in thousands):

 

 

 

Note 4. Fair Value Measurements

FASB ASC Topic 820, Fair Value Measurements and Disclosure (“ASC Topic 820”), 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. ASC Topic 820 provides a framework for measuring fair value, establishes a three level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.

The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:

Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the nine months ended September 30, 2015.

Fair Value on a Recurring Basis

Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural gas. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. These measurements were not material to the consolidated financial statements.

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands):

 

 

Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.

Fair Value on a Nonrecurring Basis

Asset Impairment

Oil and natural gas properties are measured at fair value on a nonrecurring basis. An impairment charge reduces the carrying values of oil and natural gas properties’ to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets. The Company did not recognize any impairment write-downs with respect to its oil and natural gas properties during the nine months ended September 30, 2015 or 2014.

Business Combinations

The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on NYMEX commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The future oil and natural gas pricing used in the valuation is a Level 2 assumption.   Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 2 Acquisitions.

Asset Retirement Obligations

The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. See Note 7 Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

 

 

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Note 5. Earnings (Loss) Per Common Share

Basic earnings (loss) per share is computed by dividing net income (loss) attributable to shares of Common Stock by the basic weighted-average shares of Common Stock outstanding during the period. The calculation of diluted earnings per share is similar to basic, except the denominator includes the effect of dilutive common stock equivalents.

The following table is a reconciliation of net income and weighted-average shares of Common Stock outstanding for purposes of calculating basic and diluted income per share:

 

 

 

Note 6. Long-Term Debt

On December 19, 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “ESTE Credit Facility”).  The OVR credit facility was refinanced under the ESTE Credit Facility and the legacy credit facility of the Company was paid in full and terminated.

The initial borrowing base of the ESTE Credit Facility was $80.0 million and is subject to redetermination during May and November of each year. At the option of the borrower, the amounts borrowed under the credit agreement bear annual interest rates at either (a) LIBOR plus the applicable utilization margin of 1.50% to 2.50% (1.704% at September 30, 2015) or (b) the base rate plus the applicable utilization margin of 0.50% to 1.50% (3.75% at September 30, 2015). Principal amounts outstanding under the ESTE Credit Facility are due and payable in full at maturity on December 19, 2018. All of the obligations under the credit agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Additional payments due under the credit agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment fee ranges from 0.375% to 0.50% per year, depending upon the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees.

As of September 30, 2015, the Company had $11.2 million of debt outstanding, bearing an interest rate of 1.704%, $0.3 million of letters of credit outstanding and $68.5 million of borrowing base available under its ESTE Credit Facility.

The ESTE Credit Facility contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period.  As of September 30, 2015, the Company was in compliance with these covenants.

Interest expense for the three months ended September 30, 2015 and 2014, includes amortization of deferred financing costs of $65,000 and $38,000, respectively.  Interest expense for the nine months ended September 30, 2015 and 2014, includes amortization of deferred financing costs of $195,000 and $113,000, respectively.  Approximately $1.0 million, net of amortization, associated with the Company’s credit facilities has been capitalized as of September 30, 2015 and December 31, 2014, and was being amortized over the terms of the credit agreements.

 

 

Note 7. Asset Retirement Obligations

The Company has asset retirement obligations associated with the future plugging and abandonment of oil and natural gas properties and related facilities. The accretion of the asset retirement obligation is included in “Lease operating expense” in the Condensed Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

The following table summarizes the Company’s asset retirement obligation transactions recorded during the nine months ended September 30, 2015, and in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (in thousands):

 

 

Based on expected timing of settlement, $0.3 million of the asset retirement obligation is classified as current at September 30, 2015.

 

 

Note 8. Related Party Transactions

FASB ASC Topic 850, Related Party Disclosures (“ASC Topic 850”), requires that transactions with related parties that would make a difference in decision making be disclosed so that users of the financial statements can evaluate their significance. Pursuant to ASC Topic 850, OVR and all of its members, most notably Oak Valley Management, LLC (“OVM”) and certain other members (“Certain Other Members of OVR”) are considered related parties.  The following are significant related party transactions between the Company and members of OVM as well as between the Company and Certain Other Members of OVR as of September 30, 2015 and December 31, 2014, and for the three and nine months ended September 30, 2015 and 2014.

The Company employs members of OVM. For each of the three months ended September 30, 2015 and 2014, the Company made payments totaling $0.8 million to these members as compensation for services and reimbursement of expenses. For the nine months ended September 30, 2015 and 2014, the Company made payments totaling $3.0 million and $2.9 million, respectively, to these members as compensation for services and reimbursement of expenses.  The payments are included in “General and administrative expense” on the Condensed Consolidated Statements of Operations or have been charged out to oil and natural gas properties.

The Company has business relationships with Certain Other Members of OVR and with companies that employ Certain Other Members of OVR.  At September 30, 2015 and December 31, 2014, the Company has liabilities of $1.0 million and $2.3 million, respectively, owed to such members and companies.  These amounts are included in “Accounts payable” on the Condensed Consolidated Balance Sheets.

 

 

Note 9. Income Taxes

For the three months ended September 30, 2015, the Company recorded income tax expense of $0.8 million, and for the nine months ended September 30, 2015, the Company recorded a benefit of $0.1, million both of which were deferred. The Company’s effective tax rate for the three and nine months ended September 30, 2015 was 32.1% and 32.8%, respectively, which is approximately 2% lower than the U.S. Federal statutory corporate income tax rate of 34% due to certain permanent differences.  The effective tax rate also includes approximately 0.9% of the estimated portion of the Company’s income that is subject to income tax in the states in which the Company operates. The Company did not record any tax provision for income tax in the three or nine months ended September 30, 2014 because OVR is a partnership and is not subject to taxation. As explained in Note 1 Basis of Presentation, all historical financial information prior to December 19, 2014 contained in this report is that of OVR and its subsidiaries.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with FASB ASC Topic 740, Income Taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. In recording deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax asset will be realized. The ultimate realization of deferred income tax assets, if any, is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible.

 

 

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Note 10. Commitments and Contingencies

In the course of its business affairs and operations, the Company is subject to possible loss contingencies arising from federal, state, and local environmental, health and safety laws and regulations and third party litigation.

Commitments

In 2014, the Company entered into an 18 month drilling contract to utilize a new-build drilling rig in its drilling operations.  The new rig is an upgrade and replacement of a rig with a drilling contract that was expiring.  The contract provides for a daily drilling rate of approximately $29,000.  In April 2015, the Company took delivery of the rig and commenced drilling.  As of September 30, 2015, the minimum commitment per the terms of the agreement is approximately $10.9 million. Further, in the event the Company breaks the contract and surrenders the rig, the contract provides for lump sum liquidated damages equal to approximately $20,000 per day through the end of the contract term. As of September 30, 2015 the liquidated damages amount is approximately $7.5 million.  

As a part of the 2013 Eagle Ford Acquisition, the Company and its primary working interest partner in the area ratified several long-term natural gas purchasing and natural gas processing contracts. As is customary in the industry, the Company has reserved gathering and processing capacity in a pipeline. In one of the contracts, the Company and its primary working interest partner have a volume commitment, whereby the owner of the pipeline is paid a fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity. Since the time of the acquisition, the volume commitment has not been met. The rate and terms under this purchasing and processing contract expire on June 1, 2021.  As of September 30, 2015, the Company’s share of the remaining commitment on this contract is approximately $4.7 million.

Contingencies

Environmental

The Company’s operations are subject to risks normally associated with the exploration for and the production of oil and natural gas, including blowouts, fires, and environmental risks such as oil spills or natural gas leaks that could expose the Company to liabilities associated with these risks.

In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks.

However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above.

Legal

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. In July 2015, EF Non-Op, LLC, a subsidiary of the Company, filed suit in the 125^th Judicial District Court of Harris County, Texas against the operator of its properties in LaSalle County, Texas. In the case EF Non-Op, LLC vs. BHP Billiton Petroleum Properties (N.A.), LP (F/K/A Petrohawk Properties, LP) the Company claims the operator has breached the applicable joint operating agreements in numerous ways, including improper authorization for expenditure requests, improper and imprudent operations, misrepresentation of charges and excessive billings, as well as refusal to provide requested information. The Company also claims damages from negligent representation and fraud.  The Company is seeking all relief to which it is entitled, including consequential damages and attorney’s fees. The outcome of this proceeding is uncertain, and while the Company is confident in its position, any potential monetary recovery to the Company cannot be estimated at this time.

 

 

 

 

 

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of our financial condition, results of operations, liquidity and capital resources should be read together with our unaudited condensed consolidated financial statements and notes to unaudited condensed consolidated financial statements contained in this report as well as our Annual Report on Form 10-K for the year ended December 31, 2014. Unless the context otherwise requires, the terms “the Company,” “our,” “we,” “us,” and “Earthstone” refer to Earthstone Energy, Inc. and its consolidated subsidiaries.

Statements in this discussion may be forward-looking.  These forward-looking statements involve risks and uncertainties, including those discussed below, which cause actual results to differ from those expressed.  For more information, see “Cautionary Statement Concerning Forward-Looking Statements.”

Overview

We are an independent oil and gas company engaged in the acquisition, development, exploration and production of onshore oil and natural gas reserves.  As further discussed in this report, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to acquire, discover and develop commercial quantities of oil and natural gas reserves that can be produced at a profit, and assemble an oil and natural gas reserve base with a market value exceeding its acquisition, development and production costs.

On December 19, 2014, we acquired three operating subsidiaries of Oak Valley Resources, LLC, a privately-held Delaware limited liability company (“OVR”), in exchange for shares of our common stock (the “Exchange”), which resulted in a change of control. Pursuant to the Exchange, OVR contributed to us the membership interests of its three subsidiaries, Oak Valley Operating, LLC (“OVO”), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”), in exchange for approximately 9.124 million shares, representing 84% of our common stock.  The Exchange has been accounted for as a reverse acquisition in which Oak Valley is considered the acquirer for accounting purposes.  All historical financial information prior to December 19, 2014, contained in this report is that of Oak Valley.

Immediately following the Exchange, we acquired an additional 20% undivided ownership interest in certain oil and natural gas properties located in Fayette and Gonzales Counties, Texas, (the “2014 Eagle Ford Acquisition Properties”) in exchange for the issuance of approximately 2.957 million shares of our common stock (the “Contribution Agreement”) to Flatonia Energy, LLC (“Flatonia”), increasing our ownership in these properties from a 30% undivided ownership to a 50% undivided ownership interest.  As a result of the share issuance to Flatonia, OVR’s ownership in the Company decreased from 84% to 66%.

In April 2015, we sold our Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million, recording a gain of $1.7 million.  The effective date of the transaction was March 1, 2015.

In June 2015, we acquired a 50% operated interest in two gross Austin Chalk wells which hold approximately 1,000 gross acres in southern Gonzales county, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production, with gross production of 44 barrels of oil equivalent per day (“BOEPD”) all of which was oil. Also in June, we acquired additional acreage in northern Karnes County, Texas, increasing our total leasehold position to approximately 400 gross acres.  We currently have a 33% working interest in the Karnes acreage.  These two positions are adjacent to one another and will provide 17 gross Eagle Ford locations.  We expect to begin development of this area in the fourth quarter of 2015.

In June 2015, we acquired additional acreage and increased our working interest in wells in existing Bakken units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.1 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells.  The acquisition included 164 net acres which allowed us to increase our working interest in approximately 41 producing wells and 21 wells that in the drilling and completion phase.

In August 2015, we acquired a 33% working interest in approximately 1,650 gross acres, in Southern Gonzales County, Texas for $3.3 million. This acreage supports 16 additional gross Eagle Ford locations.  

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Results of Operations

Three months ended September 30, 2015, compared to the three months ended September 30, 2014

Sales and Other Operating Revenues

The quantities of oil, natural gas, and natural gas liquids produced and sold, the average sales price per unit sold and our related revenues, exclusive of settlements related to derivative contracts for the three months ended September 30, 2015 and 2014, are presented below: 

 

 

 

Sales of Oil

For the three months ended September 30, 2015, oil revenues increased by $1.5 million or 16% relative to the comparable period in 2014. Of the increase, $14.2 million was attributable to increased volume, which was offset by $12.7 million attributable to a decrease in our realized price. The volume of oil produced and sold increased by 151 MBbls; 93 MBbls were provided by our operated Eagle Ford property as a result of additional production from new wells drilled and completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 55 MBbls of the total increase were provided by the legacy Earthstone assets. The remaining difference in oil volumes resulted from additional production on new wells in our non-operated Eagle Ford property which were partially offset by normal production declines on our other properties.  Our average realized price per Bbl decreased from $93.69 for the three months ended September 30, 2014 to $42.20 or 55% for the three months ended September 30, 2015.

Sales of Natural Gas

For the three months ended September 30, 2015, natural gas revenues decreased by $0.1 million or 7% relative to the comparable period in 2014. Of the decrease $1.0 million was attributable to the decline in our realized price which was offset by $0.9 million attributable to increased volume. Our average realized price per Mcf decreased from $4.05 for the three months ended September 30,

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2014 to $2.66 or 34% for the three months ended September 30, 2015. The volume of natural gas produced and sold increased by 221 MMcf; 23 MMcf was provided by our operated Eagle Ford property as a result of additional production from new wells drilled and completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 68 MMcf of the total was provided by the legacy Earthstone assets. Also contributing to the increase was 202 MMcf provided by our non-operated Eagle Ford property due to new wells which was partially offset by the loss of 49 MMcf from our Louisiana properties that were sold effective March 1, 2015. The remaining 23 MMcf decrease was due to production declines and variability in sales volumes in our conventional properties in Oklahoma and East Texas.  

Sales of Natural Gas Liquids

For the three months ended September 30, 2015, natural gas liquids revenues decreased by $0.3 million or 27% relative to the comparable period in 2014. Of the decrease, $1.0 million was attributable to a decrease in our realized price which was offset by a $0.7 million increase due to volume. The average realized price per Bbl decreased from $28.94 for the three months ended September 30, 2014 to $11.73 or 59% for the three months ended September 30, 2015. The volume of natural gas liquids sales produced and sold increased by 26 MBbls; 8 MBbls were provided by our operated Eagle Ford property as a result of additional production from new wells drilled and completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement. New wells on our non-operated Eagle Ford property provided 12 MBbls of the total increase; 6 MBbls of the total were provided by the legacy Earthstone assets.

Production Costs

Our production costs for the three months ended September 30, 2015 and 2014 are summarized in the table below:

 

 

Lease Operating Expenses

Lease operating expenses (“LOE”) includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges provided for in operating agreements.

 

 

Total LOE increased by $1.6 million or 63% for the three months ended September 30, 2015 relative to the comparable period in 2014, which was due to the addition of the legacy Earthstone assets, costs on the new wells that we drilled and completed after the third quarter of 2014 as well as having a larger share of the gross costs in our operated Eagle Ford property due to the additional interests we acquired in late 2014 pursuant to the Contribution Agreement. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, decreased by 16% or $1.77 per BOE from $10.95 in 2014 to $9.18 in 2015. The decrease on a per BOE basis was due to a decrease in the cost of oil field services as well as economies of scale on our operated Eagle Ford property which offset the increase that resulted from the addition of the legacy Earthstone assets which have a higher operating cost on a per BOE basis than many of our Eagle Ford wells.

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Severance Taxes

Severance taxes increased by $0.3 million or 55% for the three months ended September 30, 2015 relative to the comparable period in 2014, primarily due to the additional production from new wells drilled and completed after the third quarter of 2014 on our operated Eagle Ford property as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement in that same property and the addition of the legacy Earthstone assets. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes increased from 4.02% to 5.72%, primarily due to a shift in our sales; for the three month period ended September 30, 2015, approximately 80% of our oil, natural gas and natural gas liquids revenue came from oil versus approximately 75% in same period during 2014. These oil revenues are taxed at the full rate whereas a large portion of our natural gas and natural gas liquids sales qualify for partial or full severance tax exemptions.  Additionally, as result of the Exchange completed in late 2014, we added significant oil production from legacy Earthstone assets located in North Dakota and Montana; these states have higher severance tax rates than Texas where our operated Eagle Ford wells are located.    

Re-engineering and Workovers

Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations which include major surface repairs. These costs remained consistent for the three months ended September 30, 2015 relative to the comparable period in 2014, of which were both $0.2 million, due to the mix of projects and the variability of our working interest in the areas in which the projects are occurring. We continually evaluate these projects and weigh the advantages of the projects while seeking to control current and future expenditures.

General and Administrative Expenses

General and administrative expenses (“G&A”), primarily consist of employee remuneration, professional and consulting fees and other overhead expenses.  G&A expenses increased by $0.9 million from $1.6 million to $2.5 million for the three months ended September 30, 2015 relative to the comparable period in 2014, which was due to increased personnel costs and reporting requirements resulting from the Exchange completed in late 2014.  

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) increased during the three months ended September 30, 2015 by $2.8 million, or 54% compared to the same period in 2014, due to increased production. Despite significant additional capital costs from both acquisitions and the execution of our drilling program, on a per BOE basis DD&A decreased by 23% or $5.64 from $24.61 to $18.97 due to the proportionately greater addition of oil and gas reserves.    

Interest Expense

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense was comparable from quarter to quarter and was $0.2 million for the three months ended September 30, 2015 and 2014.

Net Gain on Derivative Contracts

During the three months ended September 30, 2015, we recorded a net gain on derivative contracts of $5.2 million, consisting of net realized gains on settlements of $1.7 million and unrealized mark-to-market gains of $3.5 million. During the three months ended September 30, 2015, all of our net realized settlements related to crude oil contracts. During the three months ended September 30, 2014, we recorded a net gain on derivative contracts of $2.5 million, consisting of net realized gains on settlements of $0.1 million and unrealized mark-to-market gains of $2.4 million.

Income Tax Expense

During the three months ended September 30, 2015 we recorded an income tax expense of $0.8 million as a result of our pre-tax net income. Our effective tax rate for the quarter was approximately 32% which is consistent with our expected annual tax rate. The annual effective tax rate is less than the US Federal statutory tax rate due to permanent differences between book and tax income; primarily the non-deductible portion of general and administrative costs. During the three months ended September 30, 2014 we did not record any provision for income tax since OVR is a partnership and for federal income tax purposes is not subject to federal income taxes or state or local income taxes that follow federal treatment. As a result of the Exchange, all historical financial information prior to December 19, 2014 contained in this report is that of OVR and its subsidiaries.

 

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Nine months ended September 30, 2015, compared to the nine months ended September 30, 2014

Sales and Other Operating Revenues

The quantities of oil, natural gas, and natural gas liquids produced and sold, the average sales price per unit sold and our related revenues, exclusive of settlements related to derivative contracts for the nine months ended September 30, 2015 and 2014, are presented below: 

 

 

 

Sales of Oil

For the nine months ended September 30, 2015, oil revenues increased by $6.3 million or 25% relative to the comparable period in 2014. Of the increase, $40.8 million was attributable to increased volume, which was offset by $34.5 million attributable to a decrease in our realized price. The volume of oil we produced and sold increased by 422 MBbls; 273 MBbls were provided by our operated Eagle Ford property as a result of additional production from new wells drilled and completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 162 MBbls of the total increase were provided by the legacy Earthstone assets. These significant increases were partially offset by production declines and variability in sales volumes in our conventional properties Texas. Our average realized price per Bbl decreased from $96.65 for the nine months ended September 30, 2014 to $46.18 or 52% for the nine months ended September 30, 2015.

Sales of Natural Gas

For the nine months ended September 30, 2015, natural gas revenues decreased by $2.0 million or 26% relative to the comparable period in 2014. Of the decrease $3.8 million was attributable to the decrease in our realized price which was offset by $1.8 million attributable to increased volume. Our average realized price per Mfc decreased from $4.54 for the nine months ended September 30, 2014 to $2.69 or 41% for the nine months ended September 30, 2015. The volume of natural gas produced and sold increased by 395 MMcf; 84 MMcf was provided by our operated Eagle Ford property as a result of additional production from new wells drilled and

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completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 206 MMcf of the total increase was provided by the legacy Earthstone assets. Also contributing to the increase, was 339 MMcf provided by our non-operated Eagle Ford property due to new wells which was partially offset by the loss of 125 MMcf from the Louisiana properties that were sold in April 2015. The remaining 109 MMcf decrease in volumes was due to decreased production in our conventional properties located in Oklahoma and East Texas.  

Sales of Natural Gas Liquids

For the nine months ended September 30, 2015, natural gas liquids revenues decreased by $0.7 million or 24% relative to the comparable period in 2014. Of the decrease, $2.8 million was attributable to a decrease in our realized price which was offset by a $2.1 million increase due to volume. The average realized price per Bbl decreased from $30.82 for the nine months ended September 30, 2014 to $13.43 or 56% for the nine months ended September 30, 2015. The volume of natural gas liquids sales produced and sold increased by 69 MBbls; 26 MBbls of the total were provided by our operated Eagle Ford property as a result of additional production from new wells as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 22 MBbls of the total were provided by the legacy Earthstone assets and 21 MBbls came from new wells drilled during 2014 and 2015 in our non-operated Eagle Ford property.

Production Costs

Our production costs for the nine months ended September 30, 2015 and 2014 are summarized in the table below:

 

 

Lease Operating Expenses

Lease operating expenses (“LOE”) includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges provided for in operating agreements.  

 

 

Total LOE increased by $5.5 million or 77% for the nine months ended September 30, 2015 relative to the comparable period in 2014, which was due to the addition of the legacy Earthstone assets, costs on the new wells that we drilling and completed after the third quarter of 2014 in our operated Eagle Ford property as well as having a larger share of the gross costs in our Eagle Ford property due to the additional interests we acquired in late 2014 pursuant to the Contribution Agreement. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, decreased by 4% or $0.37 per BOE from $10.53 in 2014 to $10.16 in 2015. The decrease on a per BOE basis was due to a decrease in the cost of oil field services as well as economies of scale on our operated Eagle Ford property which offset the increase that resulted from the addition of the legacy Earthstone assets which have a higher operating cost on a per BOE basis than many of our Eagle Ford wells.

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Severance Taxes

Severance taxes increased by $0.6 million or 43% for the nine months ended September 30, 2015 relative to the comparable period in 2014, primarily due to the additional production from new wells drilled and completed after the third quarter of 2014 in our operated Eagle Ford property as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement in that same property and the addition of the legacy Earthstone assets. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes increased from 4.16% to 5.41%, primarily due to a shift in our sales; for the nine month period ended September 30, 2015, approximately 81% of our oil, natural gas and natural gas liquids revenue came from oil versus approximately 71% in same period during 2014. These oil revenues are taxed at the full rate whereas a large portion of our natural gas and natural gas liquids sales qualify for partial or full severance tax exemptions.  Additionally, in late 2014, as result of the Exchange we added significant oil production from legacy Earthstone assets located in North Dakota and Montana; these states have higher severance tax rates than Texas where our operated Eagle Ford wells are located.

Re-engineering and Workovers

Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations which include major surface repairs. These costs decreased slightly for the nine months ended September 30, 2015 relative to the comparable period in 2014 since prior expenses reduced the need for these types of repairs in the current period. We continually evaluate these projects and weigh the advantages of the projects while seeking to control current and future expenditures.  

General and Administrative Expenses

General and administrative expenses (“G&A”), primarily consist of employee remuneration, professional and consulting fees and other overhead expenses.  G&A expenses increased by $2.7 million from $4.8 million to $7.5 million for the nine months ended September 30, 2015 relative to the comparable period in 2014, which was due to increased personnel costs and reporting requirements resulting from the Exchange completed in late 2014.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) increased during the nine months ended September 30, 2015 by $9.7 million, or 74% compared to the same period in 2014. Despite significant additional capital costs from both the acquisitions and the execution of our drilling program, on a per BOE basis depletion, depreciation and amortization remained decreased by 8% or $1.59 from $20.75 to $19.16 due to the proportionately greater addition of oil and gas reserves.    

Interest Expense

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense was comparable period over period and was $0.5 million for the nine months ended September 30, 2015 and 2014.

Net Gain on Derivative Contracts

During the nine months ended September 30, 2015, we recorded a net gain on derivative contracts of $4.5 million, consisting of net realized gains on settlements of $4.2 million and unrealized mark-to-market gains of $0.3 million. During the nine months ended September 30, 2015 our net realized settlements consisted of a $4.0 million gain related to crude oil contracts and a $0.2 million gain related to natural gas contracts. During the nine months ended September 30, 2014, we recorded a net gain on derivative contracts of $0.2 million, consisting of net realized losses on settlements of $1.0 million and unrealized mark-to-market gains of $1.2 million.

Income Tax Expense

During the nine months ended September 30, 2015 we recorded an income tax benefit of $0.1 million as a result of our pre-tax net loss. Our effective tax rate for the nine months was approximately 33% which was less than the US Federal statutory tax rate due to permanent differences between book and tax income; primarily the non-deductible portion of general and administrative costs. During the nine months ended September 30, 2014 we did not record any provision for income tax since OVR is a partnership and for federal income tax purposes is not subject to federal income taxes or state or local income taxes that follow federal treatment. As a result of the Exchange, all historical financial information prior to December 19, 2014 contained in this report is that of OVR and its subsidiaries.

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Liquidity and Capital Resources

We expect to finance future acquisition, development and exploration activities through cash flows from operating activities, borrowings under our credit facility, the sale of non-strategic assets, various means of corporate and project financing, and the issuance of additional debt and/or equity securities. In addition, we may continue to partially finance our drilling activities through the sale of participations to industry partners or financial institutions, and we could structure such arrangements on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate capital costs.

Senior Secured Revolving Credit Facility

In December 2014, we entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “Credit Agreement”) with BOKF, NA dba Bank of Texas (“Bank of Texas”), as agent and lead arranger, Wells Fargo Bank, National Association (“Wells Fargo”), as syndication agent, and the Lenders signatory thereto (collectively with Bank of Texas and Wells Fargo, the “Lender”).

The initial borrowing base of the Credit Agreement was $80.0 million and is subject to redetermination during May and November of each year. The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus the applicable utilization margin of 1.50% to 2.50% or (b) the base rate of 3.25% per year plus the applicable utilization margin of 0.50% to 1.50%. Principal amounts outstanding under the Credit Agreement are due and payable in full at maturity on December 19, 2018. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of our assets. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate ranges from 0.375% to 0.50% per year, depending upon the unutilized portion of the borrowing base in effect from time to time. We are also required to pay customary letter of credit fees.  At September 30, 2015, we had approximately $68.5 million of borrowing capacity under our Credit Agreement.  Our Credit Agreement contains customary covenants and we were in compliance with them as of September 30, 2015.

Cash Flows from Operating Activities

Substantially all of our cash flows from or used in operating activities are derived from and used in the production of our oil, natural gas, and natural gas liquids reserves.  We use any excess cash flows to fund our on-going exploration and development activities in search of new reserves. Variations in cash flows from operating activities may impact our level of exploration and development expenditures.

Cash flows provided by operating activities for the nine months ended September 30, 2015 were $4.3 million compared to $61.9 million for the nine months ended September 30, 2014.  The decrease was due to changes in our working capital items. Accounts payable and accrued expenses decreased during the nine month period ended September 30, 2015 by $15.5 million; this reduction used a significant portion of the operating cash flows we generated but positively impacted our working capital and overall balance sheet.  We believe that we have sufficient liquidity and capital resources to execute our business plan over the next 12 months and for the foreseeable future.

Cash Flows from Investing Activities

Cash applied to oil and natural gas properties for the nine months ended September 30, 2015 and 2014 was $57.7 million and $54.5 million, respectively. Cash applied to other non-oil and gas property fixed assets for the nine months ended September 30, 2015 and 2014, was $0.3 million and $0.6 million, respectively. We also used $8.7 of cash to acquire acreage and producing assets in both the Eagle Ford trend of Texas and the Bakken trend in North Dakota. The sale of our Louisiana assets provided $3.4 million of cash in the second quarter of 2015.

Derivative Instrument and Hedging Activity

We do not engage in speculative commodity trading activities and do not hedge all available or anticipated quantities of our production. In implementing our hedging strategy, we seek to effectively manage cash flow to minimize price volatility.

We seek to reduce our sensitivity to oil and natural gas price volatility and secure favorable debt financing terms by entering into commodity derivative transactions.  We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations.  

Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur.  Our open commodity derivative instruments were in a net asset position with a fair value of $3.9 million.  Based on the September 30, 2015 published commodity futures price curves for the underlying commodity, a 10% increase in per unit commodity prices would cause

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the total fair value asset of our commodity derivative financial instruments to decrease by approximately $1.3 million to a net asset of $2.6 million. A 10% decrease in per unit commodity prices would cause the total fair value net asset of our commodity derivative financial instruments to increase by approximately $1.1 million to $5.0 million. There would also be a similar increase or decrease in “Net gain on derivative contracts” in the Consolidated Statements of Operations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements in this report, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Recently Issued Accounting Standards

Revenue Recognition - In May 2014, the Federal Accounting Standards Board (“FASB”) issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods after December 15, 2017; early adoption is permitted as of the original effective date of December 31, 2016. We will adopt this standards update, as required, beginning with the first quarter of 2018. We are in the process of evaluating the impact, if any, of this guidance on our consolidated financial statements.

Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in financial statements.  Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset.  Amortization of the costs is reported as interest expense.  In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset.  The standards update is effective for interim and annual periods beginning after December 15, 2015.  We will adopt this standards update, as required, beginning with the first quarter of 2016 and it will be retrospectively applied to all prior periods.  We do not expect the adoption of this new presentation guidance to have a material impact on our consolidated balance sheets.

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination.  The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.  The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015, with early adoption permitted.  We will adopt this standard update, as required, beginning with the first quarter of 2016, and do not expect it to have a material impact on our consolidated financial statements.  

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this Item.

 

 

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.

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We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2015. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Chief Accounting Officer. Based on this evaluation, our Chief Executive Officer and Chief Accounting Officer concluded that, as of September 30, 2015, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

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PART II - OTHER INFORMATION

 

 

Item 1. Legal Proceedings

From time to time, we may be involved in various legal proceedings and claims in the ordinary course of business. As of September 30, 2015, and through the filing date of this report, we do not believe the ultimate resolution of any such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or results of operations.  

See Note 10 Commitments and Contingencies in the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this report, which is incorporated herein by reference, for material matters that have arisen since the filing of our Annual Report on Form 10-K for the year ended December 31, 2014.

 

 

Item 1A. Risk Factors

There have been no material changes during the period ended September 30, 2015 in our “Risk Factors” as discussed in Item 1A to our Annual Report on Form 10-K for the year ended December 31, 2014.

 

 

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

None.

 

 

Item 3. Defaults Upon Senior Securities

None.

 

 

Item 4. Mine Safety Disclosures

Not applicable.

 

 

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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