Attached files
| file | filename |
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| EX-31.2 - EARTHSTONE ENERGY INC | este_ex312.htm |
| EX-32.2 - EARTHSTONE ENERGY INC | este_ex322.htm |
| EX-32.1 - EARTHSTONE ENERGY INC | este_ex321.htm |
| EX-31.1 - EARTHSTONE ENERGY INC | este_ex311.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 2
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þ
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ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal Year Ended March 31, 2012
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o
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Commission file number: 0-7914
(Exact Name of Registrant as Specified in its Charter)
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Delaware
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84-0592823
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| (State of Incorporation or Organization) | (I.R.S. Employer Identification No.) | |
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633 17th Street, Suite 1900 Denver, Colorado
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80202-3619
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| (Address of principal executive office) | (Zip Code) |
(303) 296-3076
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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Common Stock, $0.001 par value per share
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NYSE MKT LLC
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Securities registered under Section 12(g) of the Act: NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No þ
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
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 (check one):
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Large accelerated filer o
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Accelerated filer o
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Non-accelerated filer o
(Do not check if a smaller reporting company)
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Smaller reporting company þ
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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
Registrant’s revenues for its most recent fiscal year: $11,712,000
The aggregate market value of registrant’s common stock held by non-affiliates was approximately $14,637,376 as of the registrant’s most recently completed second fiscal quarter.
As of June 1, 2012, 1,706,588 shares of the registrant’s common stock were outstanding.
1
EXPLANATORY NOTE
Earthstone Energy, Inc. (‘we”, “us”, “Earthstone” or the “Company”) is filing this Amendment No. 2 (the “Amendment”) on Form 10-K/A to our Annual Report on Form 10-K for the fiscal year ended March 31, 2012, as originally filed with the Securities and Exchange Commission (“SEC”) on June 5, 2012 (the “Original Report”), as amended by Amendment No. 1 filed with the SEC on June 5, 2012 (“Amendment No. 1”).
We are filing this Amendment solely to correct an error in sales volumes reported for 2012, which appear in the table under the “Results of Operation – Selected Financial Information” section on page 23 of the Original Report and thereafter correct metrics based on the incorrect sales volumes, including average sale price per Bbl and Mcf and average production expenses, gross profit and depletion expenses per BOE. The correct 2012 sales volumes are 114,960 Bbls (Oil) and 160,409 Mcf (Gas), as compared to the incorrectly reported sales volumes of 108,653 Bbls (Oil) and 226,760 Mcf (Gas). Inclusion of the corrected sales volumes does not alter or change previously reported revenue, net income or earnings per share.
In accordance with SEC Rule 12b-15, the complete text of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” has been amended and restated in its entirety in this Amendment. The disclosures in this Amendment continue to speak as of the date of the Original Report, and do not reflect events occurring after the filing of the Original Report. Accordingly, the Amendment should be read in conjunction with our other filings made with the SEC subsequent to the filing of the Original Report, including any amendments to those filings. The filing of the Amendment shall not be deemed to be an admission that the Original Report, when made, included any untrue statement of a material fact or omitted to state a material fact necessary to make a statement not misleading.
In addition, as required by SEC Rule 12b-15, new certificates by our principal executive officer and principal financial officer are filed as exhibits to this Amendment.
The complete Amendment, including the Item 7 disclosures, as amended and restated in its entirety, will be available at our web site set forth below, and will be provided without charge upon written request to the following address:
Investor Relations
Earthstone Energy, Inc.
633 Seventeenth Street, Suite 1900
Denver, Colorado 80220
(303) 296-3076 x112
info@earthstoneenergy.com
http://www.earthstoneenergy.com/contact.php
Except as described above, no other changes have been made to the Original Report and this Amendment does not amend, update or change the financial statements or any other items or disclosures in the Original Report.
2
ITEM 7
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our financial statements and related notes and the other information appearing in this report. As used in this report, unless the context otherwise indicates, references to “we,” “our,” “ours,” and “us” refer to Earthstone Energy, Inc. and its subsidiary collectively.
As an oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially and adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is to a large extent determined by factors beyond our control.
Liquidity and Capital Resources
Liquidity Outlook. Our primary source of funding is the net cash flow from the sale of our oil and natural gas production. The profitability and cash flow generated by our operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. At the current price of oil, we believe the cash generated from operations, along with existing cash balances, should enable us to meet our existing and normal recurring obligations during the next year and beyond.
Overview of our Capital Structure. We recognize the importance of developing our capital resource base in order to pursue our objectives. However, subsequent to our last public offering in 1980, debt financing has been the sole source of external funding. In addition to our routine production-related costs, general and administrative expenses and, when necessary, debt repayment requirements, we require capital to fund our exploratory and development drilling efforts and the acquisition of additional properties as well as the enhancement of held and newly acquired properties.
We have received numerous inquiries regarding the possibility of funding our efforts through equity contributions or debt instruments. Given strong cash flows, and the relatively modest nature of our current drilling projects, we have thus far declined these overtures. Our primary concern in this area is the dilution of our existing shareholders. However, going forward, given that one of the key components of our growth strategy is to expand our oil and natural gas reserve base through drilling and/or acquisitions, if we were presented with a significant opportunity and available cash and bank debt financing were insufficient, it is possible we would consider alternative forms of additional financing.
Hedging. During the years ended March 31, 2012 and 2011, we did not participate in any hedging activities, nor did we have any open futures or option contracts. Additional information concerning our hedging activities appears in Note 1 to the consolidated financial statements.
3
Working Capital. As of March 31, 2012, we had a working capital surplus of $6,572,000 (a current ratio of 2.91:1) compared to a working capital surplus as of March 31, 2011 of $4,930,000 (a current ratio of 3.96:1). The decrease in current ratio is primarily a result of the use of cash for the acquisition, development and exploration of oil and gas properties.
Cash Flow. Cash provided by operating activities doubled from $2,624,000 for the year ended March 31, 2011 to $5,278,000 for the year ended March 31, 2012. This change related primarily to the timing and collection of accounts receivable and the timing and payment of accounts payable and accrued liabilities.
Overall, net cash used in investing activities decreased from the previous year from $3,356,000 for the year ended March 31, 2011 to $2,467,000 for the year ended March 31, 2012. However, in 2012, investments in drilling and completion activities were significantly greater when compared to the prior year, but were partially offset by the sale of 38 wells in Colorado during the most recent fiscal year. During the year ended March 31, 2012, $7,687,000 was expended on the acquisition of producing properties, new horizontal Bakken wells in the Williston basin and on additional acreage, as compared to $3,302,000 during the year ended March 31, 2011.
Net cash used in financing activities for the year ended March 31, 2012 was $84,000, utilized entirely for treasury share acquisition. During the year ended March 31, 2011, $122,000 was used to purchase treasury shares. The Company’s share buyback program was adopted in October 2008 and will terminate in October 2012, if not extended before then.
Capital Expenditures
The amounts presented herein are presented on an accrual basis, and as such may not be consistent with the amounts presented on the consolidated statements of cash flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis.
During the year ended March 31, 2012, we spent $8,757,000 on various projects. This compares to $2,729,000 for the year ended March 31, 2011. During the year ended March 31, 2012, capital expenditures were comprised of drilling and completions of wells producing as of year end (47%), drilling of wells to be completed as of calendar year end (23%), converting unproductive wells to disposal wells (8%), leasehold (9%), and acquisitions of producing properties (4%). The remaining 9% of costs were primarily dedicated to recompleting existing wells. The majority (87%) of capital expenditures occurred in the Williston basin. The remainder was spent in other areas on property improvements and leasehold acreage. These projects were funded entirely with internally generated cash flow.
As of March 31, 2012, we have AFEs totaling $5,574,000 for our share in completion costs of new wells in which we share a working interest. At present cash flow levels, we expect to have sufficient funds available for our share of both the outstanding AFEs and any additional acreage, seismic and/or drilling cost requirements that might arise from our existing opportunities. We may alter or vary all or part of any planned capital expenditures for reasons including, but not limited to changes in circumstances, unforeseen opportunities, the inability to negotiate favorable acquisition, farmout, joint venture or divestiture terms, commodity prices, lack of cash flow, and lack of additional funding.
We are continually evaluating drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of evaluation. Our policy is to not disclose the specifics of a project or prospect, nor to speculate on such ventures, until such time as those various opportunities are finalized and undertaken. We caution that the absence of news and/or press releases should not be interpreted as a lack of development or activity.
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Divestitures/Abandonments
On January 31, 2012, we completed the divestiture and sale of the Company’s working and/or override interests in 38 wells in Weld County, Colorado to an unrelated third party for $5,900,000. After customary adjustments and expenses, the net proceeds from the transaction were $5,404,000. The adjusted purchase price was impacted by commissions, sales costs and post effective date revenue and expense modifications to the purchase price. The wells were considered non-core properties for the Company, given the Company’s focus on other areas, primarily the Williston Basin.
Impact of Inflation and Pricing
We deal primarily in U.S. dollars. Inflation has not had a material impact on the Company in recent years because of the relatively low rates of inflation in the United States. However, the oil and natural gas industry can be cyclical and the demand for production places pressure on the economic stability and pricing within the industry. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, cost declines are likely to lag and may not adjust downward in proportion to declining prices. Changes in prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel. While we do not presently expect business costs to materially rise, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.
Other Commitments
Other than the aforementioned outstanding AFEs, we do not have any other commitments beyond our office lease and software maintenance contracts. See Note 6 to the consolidated financial statements.
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Results of Operations
Selected Financial Information
The following provides selected financial information and averages for the years ended March 31, 2012 and 2011. Certain prior year amounts may have been reclassified to conform to the current presentation.
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Year Ended
March 31,
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2012
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2011
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Revenue
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Oil
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$
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10,401,000
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$
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6,933,000
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Gas
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1,155,000
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1,166,000
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Total revenue2
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11,556,000
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8,099,000
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Total production expense3
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4,480,000
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3,527,000
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Gross profit
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$
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7,076,000
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$
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4,572,000
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Depletion expense
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$
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1,065,000
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$
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1,131,000
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Sales volume
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Oil (Bbls)
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114,960
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93,613
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Gas (Mcf) 1
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160,409
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172,386
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Average sales price4
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Oil (per Bbl)
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$
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90.47
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$
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74.06
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Gas (per Mcf)
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$
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7.20
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$
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6.76
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Average per BOE
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Production expense3,4
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$
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31.62
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$
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28.83
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Gross profit4
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$
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49.94
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$
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37.37
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Depletion expense4
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$
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7.52
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$
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9.24
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1
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Due to the timing and accuracy of sales information received from a third party operator as described in “Volumes and Prices” below, sales volume amounts may not be indicative of actual production or future performance.
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2
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Amount does not include water service and disposal revenue. For the year ended March 31, 2012, this revenue amount is net of $156,000 in well service and water disposal revenue, which would otherwise total $11,712,000 in revenue for the year ended March 31, 2012, compared to $107,000 to total $8,206,000 for the year ended March 31, 2011.
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3
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Overall lifting cost (oil and gas production expenses and production taxes)
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4
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Averages calculated based upon non-rounded figures
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The Year Ended March 31, 2012 Compared with the Year Ended March 31, 2011
Overview. Net income for the year ended March 31, 2012, was double that of the previous year at $3,279,000 compared to $1,602,000 for the year ended March 31, 2011. The increase in the sales price per barrel of oil equivalent (“BOE”) and rise in sales volumes, offset by increases in production costs and general and administrative (“G&A”) expense, resulted in the increase in net income.
Revenues. Oil and natural gas sales revenue increased $3,457,000 (43%) for the year ended March 31, 2012, as compared to the year ended March 31, 2011, due to an overall 23% higher realized price per BOE, and 16% overall increase in sales volumes.
Volumes and Prices. On an equivalent barrel basis, sales were 142,000 BOE for the year ended March 31, 2012 compared to 122,000 BOE for the year ended March 31, 2011.
Oil sales volumes increased 23% from 93,613 barrels for the year ended March 31, 2011 to 114,960 barrels for the year ended March 31, 2012, while the average price per barrel increased 22% from $74.06 for the year ended March 31, 2011 to $90.47 for the year ended March 31, 2012. The rise in oil volumes resulted from production from the 24 newly producing wells offset, expectedly, by declines in existing wells.
Natural gas sales volumes decreased 7% from 172,386 Mcf for the year ended March 31, 2011 to 160,409 Mcf for the year ended March 31, 2012, while the average price per Mcf rose 7%, from $6.76 for the year ended March 31, 2011 to $7.20 for the year ended March 31, 2012.
Production Expenses.
Production expenses are comprised of the following items:
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Year Ended
March 31,
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2012
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2011
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Lease operating expenses
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$
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2,470,000
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$
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1,874,000
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Production taxes
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937,000
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586,000
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Workover expenses
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789,000
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856,000
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Transportation and other expenses
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284,000
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211,000
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$
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4,480,000
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$
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3,527,000
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Oil and natural gas production expense increased $953,000 (27%) for the year ended March 31, 2012, as compared to the year ended March 31, 2011. The two principal components of oil and gas production expense are routine lease operating expenses (“LOE”) and workovers. Routine expenses typically include such items as daily well maintenance, utilities, fuel, water disposal and minor surface equipment repairs. Workovers primarily include downhole repairs and are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their associated costs can be significant. Therefore, workovers account for more dramatic fluctuations in oil and gas expense from period to period.
LOE, production taxes, and transportation and other expenses increased $596,000 (32%), $351,000 (60%), and $73,000 (34%), respectively, for the year ended March 31, 2012, as compared to the year ended March 31, 2011. All fluctuate with sales revenue, which increased 43% year over year. Production taxes as a percent of oil and natural gas sales revenue were comparable year over year at 8.1% versus 7.2%. Workover expense decreased $67,000 (8%) for the year ended March 31, 2012, as compared to the year ended March 31, 2011.
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The overall lifting cost (oil and natural gas production expense plus production taxes) per BOE increased 10% from $28.83 for the year ended March 31, 2011 to $31.62 for the year ended March 31, 2012. This increase resulted from the increase LOE described above. This lifting cost per equivalent barrel is not indicative of all wells, and certain high cost wells could be shut-in should oil prices drop below certain levels.
Other Expenses.
Depletion and depreciation expense decreased $49,000 (4%) for the year ended March 31, 2012 as compared to the year ended March 31, 2011 due to the disposition of D-J Basin properties in 2012, somewhat offset by new wells. Depletion expense per BOE decreased from $9.24 for the year ended March 31, 2011 to $7.52 for the year ended March 31, 2012.
General and administrative (“G&A”) expense rose $561,000 (37%) for the year ended March 31, 2012, as compared to the year ended March 31, 2011. Eighty percent of this increase relates to personnel costs, as additional management, staff and a Board member were added in 2012. State franchise taxes resulted in 15% of the rise in costs. The sum of various other administrative costs account for the remaining fluctuation in the expense. As a percent of total sales revenue, G&A expense remained steady at 18% both years.
Income Tax. For the year ended March 31, 2012, we recorded income tax expense of $652,000. This amount consisted of a current period expense of $240,000, and deferred tax expense of $412,000. Our effective income tax rate increased from 11.41% for the year ended March 31, 2011 to 16.59% for the year ended March 31, 2012. Our effective income tax rate was higher for the year ended March 31, 2012, primarily due to the tax gain on the sale of the D-J Basin properties, offset by the utilization of greater percentage depletion as a result of recognizing the gain from the these properties.
Critical Accounting Policies and Estimates
See Note 1 to the consolidated financial statements.
Recent Accounting Pronouncements
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company is required to implement this guidance effective for the first quarter of fiscal 2014 and does not expect the adoption of ASU 2011-11 to have a material impact on its consolidated financial statements.
Various other accounting pronouncements have been recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to have a material effect on our financial position, results of operations, or cash flows.
Off Balance Sheet Arrangements
We have no significant off balance sheet transactions, arrangements or obligations.
Part IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(b) The following exhibits are filed as part of this report.
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Exhibit No.
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Document
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Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer), filed herewith.
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Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial Officer), filed herewith.
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Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer), filed herewith.
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Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial Officer), filed herewith.
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In accordance with the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this amendment to be signed on its behalf by the undersigned, thereunto duly authorized by the following in the capacities and on the dates indicated.
EARTHSTONE ENERGY, INC.
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Name and Capacity
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Date
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By: /s/ Ray Singleton
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July 13, 2012
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Ray Singleton, President and
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Chief Executive Officer
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By: /s/ Jim Poage
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July 13, 2012
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Jim Poage, Interim Chief Financial Officer
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In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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Name and Capacity
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Date
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By: /s/ Ray Singleton
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July 13, 2012
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Ray Singleton, Director
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By: /s/ Richard K. Rodgers
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July 13, 2012
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Richard K. Rodgers, Director and
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Compensation Committee Chairman
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By: /s/ Monroe W. Robertson
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July 13, 2012
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Monroe W. Robertson, Director and
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Audit Committee Chairman
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By: /s/ Andrew P. Calerich
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July 13, 2012
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Andrew P. Calerich, Director
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