ITEM 1A
RISK FACTORS
While we acknowledge that we have certain risk factors, smaller reporting companies are not required to provide information under this Item. Therefore, the absence of reporting under this Item should not be construed to indicate that we have no risk factors. Instead, we recognize that we have the same or similar risk factors as other comparable companies within our industry; especially companies with similar market capitalization and/or employee census.
ITEM 1B
ITEM 1B
UNRESOLVED STAFF COMMENTS
None.
ITEM 2
ITEM 2
DESCRIPTION OF PROPERTY
Producing Properties: Location and Impact
At March 31, 2010, we owned a working interest in 101 producing oil wells and 39 producing gas wells in five states: North Dakota, Montana, Colorado, Texas and Wyoming. Virtually all of our property and production are pledged to secure any use of our bank line of credit. Refer to Credit Line under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for further information.
Productive Wells
(1)
The number of gross wells is the total number of wells in which a working interest is owned.
(2)
A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
Production
Specific production data relative to our oil and gas producing properties can be found in the Selected Financial Information table in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Reserves
At March 31, 2010, our estimated proved developed and undeveloped oil and gas reserves in barrels of oil equivalent (BOE) was 970,000, a 22.2% increase from the prior year’s estimated proved developed oil and gas reserves of 794,000 BOE. This increase was primarily caused by an increase in the 12 month average of the price of oil and gas on the first day of each month during fiscal 2010 when compared to the price on March 31 2009.
Geographically, our reserves are located in three primary areas: the Williston basin in North Dakota and Montana, the Denver-Julesburg (D-J) basin in Colorado and on-shore south Texas. The following table summarizes the estimated proved developed and undeveloped oil and gas reserves divided between operated and non-operated properties for these three areas as of March 31, 2010:
Estimated Proved Oil and Gas Reserves by Area
(1)
Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)
In March 2010, we adopted revised oil and gas reserve estimation and disclosure requirements which conforms the definition of proved reserves within the Modernization of Oil and Gas Reporting rules, which were issued by the Securities and Exchange Commission (“SEC”) at the end of 2008. The new accounting standard requires that the 12-month average of the first-day-of-the-month price for the preceding year, rather than the year-end price, be used when estimating reserve quantities. Furthermore, it permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Prior-year data are presented in accordance with Financial Accounting Standards Board (“FASB”) oil and gas disclosure requirements effective during those periods.
Preparation of Proved Reserves Estimates
Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance. Oil and gas reserves have been estimated as of March 31, 2010 for a significant portion of our properties by the Ryder Scott Company (“Ryder Scott”) of Houston, Texas. Ryder Scott estimated reserves for properties located in the states of Colorado, Louisiana, Montana, North Dakota and Texas comprising approximately 93% and 98% of the PV-10 of our oil and gas reserves as of March 31, 2010 and March 31, 2009, respectively. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. Ryder Scott has over eighty engineers and geoscientists on their permanent staff. Ryder Scott prepares our reserve estimate based upon a review of property interests being appraised, production from such properties, average annual costs of operation and development, commodity prices for production that comply with the new SEC guidelines and other engineering data/information we provide to them. This information is reviewed by knowledgeable members of our company, including our President and Chief Executive Officer, to ensure accuracy and completeness of the data prior to and after submission to Ryder Scott. The report of Ryder Scott dated May 3, 2010, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.3 to this report.
We concluded that it was not cost effective to have Ryder Scott prepare reserve estimates for 32 of our 91 properties because of their relatively low values. Instead, reserves for these properties were prepared by in-house personnel and contributed 7% and 2% of our reserves as of March 31, 2010 and March 31, 2009, respectively. In-house reserve estimates were prepared by Ray Singleton, President and Chief Executive Officer. Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. In his capacity as an engineer, Mr. Singleton prepared reserve and economic estimates during his employment with both Amoco Production Company and Champlin Petroleum. Mr. Singleton continued providing economic evaluations for approximately 40 different clients through his engineering consulting firm, Singleton & Associates, from 1982 to 1988, and thereafter for Earthstone Energy, Inc. since his employment in 1988. In addition, Mr. Singleton is currently a member of the Society of Petroleum Engineers.
Technologies Used in Preparation of Proved Reserves Estimates
All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods used are limited to decline curve analysis which utilized extrapolations of historical production data. All proved undeveloped reserves were estimated by analogy. This is done by consideration of the assumptions, data, methods and analytical procedures.
Oil and gas reserves and the estimates of the present value of future net revenues were determined based on prices and costs as prescribed by SEC and FASB guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves were estimated in accordance with guidelines established by the SEC and FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.
The following table sets forth certain information regarding estimates of our oil and gas reserves as of March 31, 2010. All of our reserves are located in the United States.
Estimated Proved Developed and Undeveloped Oil and Gas Reserves
(1)
Disclosure of probable and possible reserves became optional under SEC guidelines for years ended March 31, 2010, and accordingly, we have elected not to present probable or possible reserves.
The process of estimating oil and gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this Annual Report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.
Proved Undeveloped Reserves
At March 31, 2010, we had 91,000 barrels of proved undeveloped reserves, which will require future capital expenditures of approximately $991,000 to develop. At March 31, 2009 we had one proved undeveloped property. During fiscal 2010 this property was re-classified to the proved and developed category. Approximately $490,000 was spent in this development effort. None of the proved undeveloped reserves at March 31, 2010 have been on our reserve report for more than five years.
Oil and Gas Production and Sales Prices
Refer to Selected Financial Information in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the table which presents our net oil and gas production, the average sales price per Bbl of oil and per Mcf of gas produced and the average cost of production per BOE of production sold, for the three years ended March 31, 2010.
Drilling Activities
The following table sets forth our gross and net working interests in exploratory and development wells drilled during the three years ended March 31, 2010:
Exploratory and Developmental Wells Drilled
(1)
An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
(2)
A development well is a well drilled in a proven territory in a field to complete a pattern of production
Leasehold Acreage
We lease the rights to explore for and produce oil and gas from mineral owners. Leases (quantified in acres) expire after their primary term unless oil or gas production is established. Prior to establishing production, leases are generally considered undeveloped. After production is established, leases are considered developed or “held-by-production.” Our acreage is comprised of developed and undeveloped acreage as follows:
Gross and Net Acreage
(1)
Undeveloped acreage encompasses leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas.
(2)
The number of gross acres is the total number of acres in which a working interest is owned.
(3)
A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Field Service Equipment
At March 31, 2010, our remaining active subsidiary, Basic Petroleum Services, Inc. located in Bruni, Texas, owned a trailer house/field office, a shallow pulling rig, a large winch truck, a skid-mounted cementing unit, four pickup trucks and various ancillary service vehicles. None of the vehicles are encumbered.
Office Lease
We currently lease approximately 4,000 square feet of office space in downtown Denver, Colorado from an independent third party for approximately $5,853 per month escalating at a rate of approximately $170 at the end of each year. The lease term is for a five-year period ending April 30, 2013. For additional information see Note 7 to the Consolidated Financial Statements.
ITEM 3
ITEM 3
LEGAL PROCEEDINGS
None.
Part II
ITEM
MARKET FOR REGISTRANT’S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Price Range of Common Stock, Number of Holders and Dividend Policy
Our common stock is currently quoted on the Over-the-Counter Bulletin Board (“OTCBB”). The OTCBB is a network of security dealers who buy and sell stock. The dealers are connected by a computer network that provides information on current “bids” and “asks,” as well as volume information. Our shares are quoted on the OTCBB under the symbol “BSIC.”
The following table sets forth the range of high and low bid quotations for our common stock for each of the periods indicated below as reported by the OTCBB. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions. The closing bid price on June 18, 2010 was $1.30.
As of June 18, 2010, we had approximately 3,919 shareholders of record. We have never paid a cash dividend on our common stock. Our loan agreement has a covenant prohibiting the payment of dividends to stockholders without our lender’s prior written consent. Any future dividend on common stock will be at the discretion of the Board of Directors and will be dependent upon the Company’s earnings and financial condition, receipt of our lender’s consent and other factors. Our Board of Directors presently has no plans to pay any dividends in the foreseeable future.
Unregistered Sales of Equity Securities
Not applicable.
Securities Authorized For Issuance under Equity Compensation Plans
The following table contains information with respect to our Director Compensation Plan as of the end of our fiscal year ended March 31, 2010.
Equity Compensation Plan Information
The Board adopted a Director Compensation Plan (the “Plan”), effective April 1, 2007, which provides for a combination of cash and equity incentive compensation to attract and retain qualified and experienced director candidates. Under the Plan, each independent, non-employee director receives an annual grant of restricted stock having a fair market value equal to $36,000 on April 1 of each year. The number of shares included in each annual grant is determined based upon the average closing price of the ten trading days preceding April 1 of each year. Up to 507,276 shares of the Company’s common stock may be issued to directors under the Plan, subject to certain restrictions and vesting. Grants of shares of restricted stock vest one-third each year over three years.
During the end of our fiscal year ended March 31, 2010, 207,276 shares of common stock reserved for issuance under the Plan had been authorized for issuance. On March 31, 2010, the Plan was amended to authorize an additional 300,000 shares for issuance. As of June 18, 2010, 294,444 shares of common stock reserved for issuance under the Plan had been granted. Accordingly, 212,832 shares of common stock remain available for issuance under the Plan. In accordance with the terms of the Plan, if a Director’s participation as a member of the Board ceases or is terminated for any reason prior to the date the shares of restricted stock are fully vested, the unvested portion of the restricted stock shall be automatically forfeited and shall revert back to the Company. The aggregate number of restricted stock awards outstanding and subject to vesting at the fiscal year ended March 31, 2010, for each director was as follows: Robertson - 76,484 shares; and Rodgers - 76,484. In addition, each director was granted 43,584 shares of restricted stock on April 1, 2010, subject to vesting and forfeiture.
Purchases of Equity Securities
The following table summarizes monthly stock repurchase activity for the fourth quarter for the fiscal year ended March 31, 2010:
(1)
On October 22, 2008, the Company’s Board of Directors authorized a stock buyback program for the Company to repurchase up to 500,000 shares of its common stock for a period of up to 18 months. The program does not require the Company to repurchase any specific number of shares, and the Company may terminate the repurchase program at any time. On November 13, 2009, the board of directors increased the number of shares authorized for repurchase to 1,500,000. On February 10, 2010, the board extended the termination date of the program from April 22, 2010 to October 22, 2011. During the year ended March 31, 2010, 265,430 shares were repurchased under the stock buyback program and 1,204,370 shares remain available for future repurchase.
ITEM 6
ITEM 6
SELECTED FINANCIAL DATA
Smaller reporting companies are not required to provide the information required by this Item.
ITEM 7
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.
Liquidity Outlook
Our primary source of funding is the net cash flow from the sale of our oil and 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 then sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. Assuming oil prices do not decline significantly from current levels, we believe the cash generated from operations will provide sufficient working capital for us to meet our existing and normal recurring obligations as they become due. In addition, as mentioned in the “Debt” section below, we have an available borrowing capacity of $4,000,000 as of June 18, 2010.
Capital Structure and Liquidity
Overview. 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 any development and enhancement of these 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 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.
Credit Line. Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Effective January 3, 2006 we amended the existing loan agreement to increase the line of credit amount from $1,000,000 to $20,000,000 with a concurrent borrowing base increase from $1,000,000 to $4,000,000. Effective December 31, 2008 the loan agreement was amended again to extend the maturity date of the credit facility to December 31, 2010.
Under the credit facility, we must maintain certain financial covenants. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. The loan agreement has covenants requiring us to maintain a debt-to-equity ratio of less than one and a current ratio of at least 1:1 inclusive of unused borrowing capacity and exclusive of the current portion of long-term debt. We were in compliance with all covenants at March 31, 2010.
During the years ended March 31, 2010 and 2009, we utilized none of our credit facility. Our effective annual interest rate is 6.50% or prime plus 0.25%, whichever is greater. On June 18, 2010 we had no outstanding principal balance on the line of credit, with the entire $4,000,000 available for borrowing. If necessary, we may borrow funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions or pursue other opportunities. See Note 6 to the Consolidated Financial Statements for a more detailed discussion of our bank credit facility.
Hedging. During 2010 and 2009, 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.
Working Capital. At March 31, 2010, we had a working capital surplus of $5,062,000 (a current ratio of 3.53:1) compared to a working capital surplus at March 31, 2009 of $5,045,000 (a current ratio of 4.62:1).
Cash Flow. As mentioned above, our primary source of funding is the cash flow from our operations. Cash provided by operating activities decreased 7.2% from $2,872,000 in 2009 to $2,666,000 in 2010. Net cash used in investing activities decreased 62.2% from $4,338,000 in 2009 to $1,641,000 in 2010, which relates primarily to our drilling and completion activities during the year.
We have not borrowed on our line of credit since June 2006. Cash used in financing activities was $17,000 in 2009 for the purchase of treasury shares net of proceeds from the exercise of the remaining stock options outstanding, while cash used in financing activities was $208,000 in 2010 for the purchase of treasury shares.
Capital Expenditures. During 2010 our capital expenditures were primarily focused on properties in the Williston Basin of Montana and North Dakota. On an accrual basis, total capital expenditures during 2010 for oil and gas property and equipment and various leasehold interests were $2,156,000. Of these expenditures, $1,887,000 (87.5%) is attributable to the Williston Basin for the drilling, completion and leasehold costs of wells in this area. These projects were funded entirely with internally generated cash flow. See also the Areas of Focus and Company Developments sections of Part 1 of this report for further discussion related to our exploration and development activities.
We are continually evaluating exploration, development and acquisition opportunities in an effort to grow our oil and gas reserves. At present cash flow levels and available borrowing capacity, we expect to have sufficient funds available for our share of any additional acreage, seismic and/or drilling cost requirements that might arise from these opportunities. However, we may alter or vary all or part of these planned capital expenditures based upon changes in circumstances, unforeseen opportunities, inability to negotiate favorable acquisition, farmout or joint venture terms, lack of cash flow, lack of additional funding, if necessary, and/or other events which we are not able to anticipate.
Divestitures/Abandonments. We plugged two wells during 2010 and incurred some additional costs pertaining to the abandonment of wells that are in the process of being plugged.
Impact of Inflation. We deal primarily in US 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.
Other Commitments. We have no obligations to purchase additional, or sell any existing, oil and gas property. We also do not have any other commitments beyond our office lease and software maintenance contracts (see Note 7 to the Consolidated Financial Statements).
Results of Operations
Selected Financial Information
The following table shows selected financial information and averages for each of the three prior years in the period ended March 31.
Due to the timing and accuracy of sales information received from a third party operator as described in “Volumes and Prices” above, sales volume amounts may not be indicative of actual production or future performance.
Amount does not include water service and disposal revenue. For the year ended March 31, 2010 this revenue amount is net of $50,000 in water service and disposal revenue, which would otherwise total $7,269,000 in revenue for the year ended March 31, 2010, compared to $95,000 and $32,000 to total $9,086,000 and $7,447,000 for the same periods in 2009 and 2008 respectively.
Overall lifting cost (oil and gas production expenses and production taxes)
Averages calculated based upon non-rounded figures
Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)
Fiscal 2010 Compared with Fiscal 2009
Overview. Net income for the year ended March 31, 2010 was $1,028,000 compared to net income of $578,000 for the year ended March 31, 2009, a 77.9% increase. This increase is more a function of depressed income in 2009 rather than results in 2010. Net income in 2009 was adversely impacted by a sizeable impairment expense due to a significant decline in oil and gas prices during the third quarter of 2009. With rising prices in 2010, a similar expense was not incurred in the current year. While oil and gas sales volume increased in 2010, these increases were partially offset by decreased average commodity prices when compared to 2009. While overall production expenses decreased during 2010, general and administrative increased.
Revenues. Oil and gas sales revenue decreased $1,772,000 (19.7%) in 2010 over 2009 as a result of overall lower average oil and gas prices despite increased oil and gas production. Oil sales revenue decreased $1,183,000 (16.0%) and Gas sales revenue decreased $589,000 (37.2%) in 2010 from 2009.
Volumes and Prices. Oil sales volumes increased 6.7% from 92,657 barrels in 2009 to 98,865 barrels in 2010, while the average price per barrel decreased 21.2% from $79.93 in 2009 to $62.94 in 2010. Gas sales volume increased 30.3% from 175.4 million cubic feet (MMcf) in 2009 to 228.6 MMcf in 2010. The average price per Mcf decreased 51.8%, from $9.04 in 2009 to $4.36 in 2010. The production increase in gas in 2010 was primarily due to adjustments made during the year, to our revenues, sales volumes, sales prices and severance taxes following the receipt of higher production and sales volume information related to the Antenna Federal property in Weld County, Colorado. Most of the Company’s gas sales are from our non-operated interest in the Antenna Federal property in Weld County, Colorado. During the prior year, the Company had estimated gas sales on this property based on the information available at the time and the Company’s experience in the area. During 2010, we received actual sales volumes and related information from the operator, which were significantly higher than the sales volumes and related information previously reported to, and accrued by, the Company in the prior year. The incorporation of this information resulted in higher sales volumes, sales prices and severance taxes for the current year. Due to the adjustments made during 2010, for updated sales volumes and related information received from the operator of the Antenna Federal property, the higher sales volumes for 2010, are not representative of actual sales volume for this year and should not be used to predict future production or sales volumes. In addition, production taxes as a percentage of sales, general and administrative expenses as a percentage of sales and any metric whose denominator is related to sales volumes is likely understated. On an equivalent barrel (BOE) basis, sales increased 12.3% from 122,000 BOE in 2009 to 136,961 BOE in 2010.
Expenses. Oil and gas production expense decreased $102,000 (4.0%) in 2010 over 2009. Oil and gas production expense is comprised of two components: routine lease operating expenses 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 production expense from period to period.
Routine lease operating expense increased $16,000 (0.8%) from $1,969,000 in 2009 to $1,985,000 in 2010, which is relatively comparable. Workover expense decreased $118,000 (20.7%) from $570,000 in 2009 to $452,000 in 2010 related to an overall decrease in workovers of various wells primarily located in the Williston basin of Montana and North Dakota. On an equivalent barrel basis, routine lease operating expense decreased 10.2% from $16.14 per BOE in 2009 to $14.49 in 2010, while workover expense decreased 29.4% from $4.67 in 2009 to $3.30 per BOE in 2010.
Production taxes, which are a function of sales revenue, decreased $146,000 (22.7%) in 2010 from 2009. Production taxes as a percent of oil and gas sales revenue decreased from 7.1% in 2009 to 6.9% in 2010.
The overall lifting cost (oil and gas production expense plus production taxes) per BOE was $21.43 in 2010 compared to $26.09 in 2009. The decrease primarily related to the decrease in production taxes as described in the preceding paragraph. 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.
Depreciation and depletion expense decreased $3,000 (0.2%) in 2010 from 2009. Depreciation and depletion expense per BOE decreased from $10.03 in 2009 to $8.91 in 2010.
Accretion of asset retirement obligation increased $68,000 (69.4%) in 2010 from 2009. This increase is a result of new well additions during the year and revisions to the estimated lives of some of our wells sharing the same leased acreage. Additional information concerning asset retirement obligations and related activity during 2010 can be found in Note 5 to the Consolidated Financial Statements.
Impairment of oil and gas properties occurred during the prior year as a result of the decline in oil and gas prices. Like a number of companies in our industry, we incurred a charge consistent with the results of our “ceiling test” which places a “ceiling” on our capitalized costs, thereby limiting our pooled capital costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds this “ceiling,” we are required to record a write-down to the extent of such excess. This write-down is a non-cash charge to earnings. It reduces earnings and impacts shareholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. Accordingly, during the year ended March 31, 2009, we determined that our capitalized costs exceeded the ceiling test limit and recorded an impairment write-down of $2,694,000, compared to no ceiling test impairment for the year ended March 31, 2010.
General and administrative (G&A) expense increased $432,000 (32.1%) in 2010 over 2009. This increase was primarily due to consulting fees in connection with investor relations and SEC reporting requirements, legal fees and related proxy and shareholder expenses and increased executive compensation. The percentage of G&A expense that was billed out to operated properties was 11.7% in 2010 compared to 14.4% in 2009. G&A expense per BOE increased 17.6% from $11.04 in 2009 to $12.99 in 2010. G&A expense as a percentage of total sales revenue also increased from 14.8% in 2009 to 24.5% in 2010.
Other Income/Expense. Interest and other income increased from $57,000 in 2009 to $90,000 in 2010 due to increases in miscellaneous items. Interest and other expenses decreased from $34,000 in 2009 to $32,000 in 2010.
Income Taxes. In 2010, we recorded income tax expense of $148,000 comprised of a current year income tax provision of $172,000, and a deferred income tax benefit of $24,000. This compares to a 2009 income tax benefit of $212,000. At March 31, 2009, we had a net deferred tax benefit of $(558,000). Our effective income tax rate increased from (56.34)% for 2009 to 12.57% for 2010. Our effective income tax rate was lower for 2009 primarily due to an increase in estimated deductions for statutory depletion and impairment expense.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the actual amounts of assets and liabilities at the date of the financial statements and the actual amounts of revenues and expenses during the reporting period. We base these estimates on assumptions that we understand are reasonable under the circumstances. The estimated results that are produced by this effort will differ under different assumptions or conditions. We understand that these estimates are necessary and that actual results could vary significantly from the estimated amounts for the current and future periods. We understand the following accounting policies and estimates are necessary in the preparation of our consolidated financial statements: the carrying value of our oil and gas property, the accounting for oil and gas reserves, the estimate of our asset retirement obligations and the estimate of our income tax assets and liabilities.
Oil and Gas Property. We utilize the full cost method of accounting for costs related to our oil and gas property. Capitalized costs included in the full cost pool are depleted on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and may result in lower depreciation and depletion in future periods. The write-down cannot be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.
Oil and Gas Reserves. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of our oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves attributable to these properties. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are often different from the quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. Ninety-three percent of our reported oil and gas reserves at March 31, 2010 are based on estimates prepared by an independent petroleum engineering firm. The remaining seven percent of our oil and gas reserves were prepared in-house. See also Note 12 to the Consolidated Financial Statements.
Asset Retirement Obligations. We have significant obligations related to the plugging and abandonment of our oil and gas wells, the removal of equipment and facilities and returning the land to its original condition. As we account for asset retirement obligations we are required to estimate the future cost of this obligation, discount this cost to its present value, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash expenditures and inflation rates. The nature of these estimates requires management to make judgments based on historical experience and future expectations related to timing. We review the estimate of our future asset retirement obligations quarterly. These quarterly reviews may require revisions to these estimates based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. See also Note 5 to the Consolidated Financial Statements.
Off Balance Sheet Arrangements
We have no significant off balance sheet transactions, arrangements or obligations.
Recent Accounting Pronouncements
There have been several recent accounting pronouncements, but none are expected to have a material effect on our financial position, results of operations, or cash flows. For more information, see Note 1 - “Recent Accounting Pronouncements” in the Notes to Consolidated Financial Statements.
ITEM 7A
ITEM 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
Smaller reporting companies are not required to provide the information required by this Item.
ITEM 8
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Earthstone Energy, Inc.
Consolidated Financial Statements
and Accompanying Notes
March 31, 2010 and 2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Earthstone Energy, Inc.
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Earthstone Energy, Inc. and Subsidiaries (the “Company”) as of March 31, 2010 and 2009, and the related statements of operations, shareholders’ equity, and cash flows for the years ended March 31, 2010 and 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Earthstone Energy, Inc. as of March 31, 2010 and 2009, and the results of their operations and their cash flows for the years ended March 31, 2010 and 2009 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, as of March 31, 2010, the Company has changed its method of determining quantities of oil and gas reserves which impacted the amount recorded for depreciation and depletion for oil and gas properties.
Ehrhardt Keefe Steiner & Hottman PC
Denver, Colorado
June 18,
Earthstone Energy, Inc.
Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
Earthstone Energy, Inc.
Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
Earthstone Energy, Inc.
Consolidated Statements of Operations
See accompanying notes to consolidated financial statements.
Earthstone Energy, Inc.
Consolidated Statements of Shareholders’ Equity
Years Ended March 31, 2010 and 2009
See accompanying notes to consolidated financial statements.
Earthstone Energy, Inc.
Consolidated Statements of Cash Flows
See accompanying notes to consolidated financial statements.
Earthstone Energy, Inc.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Organization and Nature of Operations. Earthstone Energy, Inc. (“Earthstone” or “the Company” or “we” or “our” or “us”), was originally organized in July 1969 as Basic Earth Science Systems, Inc. We changed our name in 2010 to Earthstone Energy, Inc. We are principally engaged in the acquisition, exploitation, development, operation and production of crude oil and natural gas. Our primary areas of operation are the Williston basin in North Dakota and Montana, south Texas and the Denver-Julesburg basin in Colorado.
Principles of Consolidation. The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
Oil and Gas Sales. We derive revenue primarily from the sale of produced natural gas and crude oil. We report revenue on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded using the sales method, which occurs in the month production is delivered to the purchaser, at which time title changes hands. Payment is generally received between 30 and 90 days after the date of production. We make estimates of the amount of production delivered to purchasers and the prices we will receive. We use our knowledge of our properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received, or when better information is available.
Oil and Gas Properties. We follow the full cost method of accounting for our oil and gas activity. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized, with the exception of unproved properties which are periodically reviewed for impairment by reviewing the status of the activity on those properties and surrounding properties either held by us or other parties. Capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves using the 12 month average price of oil and gas on the first day of each month and costs discounted at 10 percent plus the lower of cost or fair value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. While we did not incur a ceiling limitation charge for the year ended March 31, 2010, we incurred a ceiling test limitation charge in the amount of $2,694,000 during the year ended March 31, 2009, representing the excess of capitalized costs over the ceiling, as calculated in accordance with these full cost rules.
All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties we own. Depletion expense per equivalent barrel of production was $8.65 and $9.74 for 2010 and 2009, respectively.
Income Taxes. We account for income taxes in accordance with FASB issued authoritative guidance which requires the use of the “liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial statement and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. For further information, see Note 9 below.
Earnings Per Share. Our earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of securities, if any, that could share in the earnings of the Company and is calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options. The following is a reconciliation of basic and diluted earnings per share for the years ended March 31, 2010 and 2009:
There were no options issued or outstanding for 2010 or 2009. See Note 8 below for further discussion of our stock options.
Cash and Cash Equivalents. For purposes of the Consolidated Balance Sheets and Statements of Cash Flows, we consider all highly liquid investments with a maturity of ninety days or less when purchased to be cash equivalents. The carrying amount of cash equivalents approximates fair value because of the short-term maturity of those instruments. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.
Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities. The carrying value of cash and cash equivalents, trade receivables, trade payables and accrued liabilities are considered to be representative of their fair market value, due to the short maturity of these instruments.
Hedging Activities. We had no hedging activities in 2010 and 2009. Hedging strategies, or absence of hedging, may vary or change due to change of circumstances, unforeseen opportunities, inability to fund margin requirements, lending institution requirements and other events which we are not able to anticipate.
Support Equipment and Other. Support equipment (including such items as vehicles, office furniture and equipment and well servicing equipment) is stated at cost. Depreciation of support equipment and other property is computed using primarily the straight-line method over periods ranging from five to seven years.
Inventory. Inventory, consisting primarily of tubular goods and oil field equipment, is stated at the lower of cost or market, cost being determined by the FIFO method. See also Notes 2 and 3 below.
Long-Term Assets. We apply FASB issued authoritative guidance to long-lived assets not included in oil and gas properties. Under the guidance, all long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. An impairment loss is recognized when the carrying value of a long-lived asset is not recoverable and exceeds its fair value.
Major Customers and Concentration of Credit Risk. Purchasers of 10% or more of our oil and gas production revenue received at March 31, 2010 and 2009 are as follows:
It is not expected that the loss of any one of these purchasers would cause a material adverse impact on our operations because alternative markets for our products are readily available.
In the year ended March 31, 2010, approximately 57% of our oil and gas revenue was received from non-operated properties where we have no control over the selection of the purchaser. On these properties our portion of the product was marketed on our behalf by the 21 different companies who operate these wells. These 21 companies may, unbeknownst to us, market to one or more of the same purchasers that we use. Therefore, we are unable to ascertain the total extent of combined purchaser concentration. To the extent of our knowledge, in the event of the bankruptcy of any one of our purchasers, or purchasers on non-operated properties, it has been estimated that the reduction in annual revenue would be less than 10%.
Stock Option Plan. We are required to recognize all equity-based compensation, including stock option grants, as stock-based compensation expense in our Consolidated Statements of Operations based on the fair value of the compensation. No options have been granted since July 2003, and the plan expired in July 2005. Therefore, we issued no further stock options in either 2010 or 2009. See Note 8 below for further discussion of the Company’s stock options.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of oil and gas reserves as well as the 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. There are many factors, including global events, which may influence the production, processing, marketing, and pricing of crude oil and natural gas. A reduction in the valuation of oil and gas properties resulting from declining prices or production could adversely impact depletion rates and ceiling test limitations. Estimates of oil and gas reserve quantities provide a basis for calculation of depletion expense as well as the potential for impairment.
Reclassifications. Certain prior year amounts were reclassified to conform to current year presentation. Such reclassifications had no effect on the prior year net income.
Recent Accounting Pronouncements
In June 2009, the FASB issued Accounting Standards Codification, “Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Codification”) which will become the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. This Statement is effective for financial statements issued for interim and annual periods ended after September 15, 2009. The adoption of the Codification did not have a material impact on our consolidated financial statements or results of operations.
In June 2009, the FASB issued guidance related to subsequent events which incorporates the guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. In February 2010, the FASB issued an update to this guidance which no longer requires the Company to disclose the date through which subsequent events have been evaluated. We adopted this update which had no impact on the Company’s consolidated financial statements or results of operations.
On April 29, 2009, the FASB issued guidance related to financial instruments, which requires publicly-traded companies to provide disclosures on the fair value of financial instruments in interim financial statements, and is effective for interim periods ended after June 15, 2009. We have adopted these new provisions, which did not have a material impact on the Company’s consolidated financial statements or results of operations.
On April 1, 2009, the FASB issued guidance related to business combinations, which addresses application issues associated with initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination, including the treatment of contingent consideration, acquisition costs, research and development assets and restructuring costs. In addition, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. The new guidance is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will apply the new provisions to future acquisitions.
In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements is a broader definition of reserves, which allows reporting of probable and possible reserves, in addition to consideration of new technologies and non-traditional resources. In addition, oil and gas reserves will be reported using an average price based on the first-day-of-the-month price during the prior 12-month period, rather than year-end prices. The new rules are effective for years ending on or after December 31, 2009. The adoption of the new rules is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or financial statements which also impact the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new guidance, subsequent price increases cannot be considered in the ceiling test calculation. The Company does not believe that it is practicable to estimate the effect of applying the new rules on net loss or the amounts recorded for depreciation, depletion and amortization and ceiling impairment for the year ended March 31, 2010.
In September 2006, the FASB issued guidance related to fair value measurements and disclosures, which defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. The new guidance is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB proposed a one year deferral of the implementation for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On April 1, 2008, we adopted the new guidance with the one-year deferral for non-financial assets and liabilities. The adoption of the new guidance did not have a material impact on our financial position, results of operations or cash flows. Beginning April 1, 2009, we have adopted the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. The adoption did not have a material impact on our financial statements.
2. Other Current Assets
Other current assets at March 31, 2010 and 2009 consisted of the following:
The lease and well equipment inventory included in Other Current Assets represents well-site production equipment owned by us that has been removed from wells that we operate. This occurs when we plug a well or replace defective, damaged or suspect equipment on a producing well. In this case, salvaged equipment is valued at prevailing market prices, removed from the full cost pool and made available for sale. This equipment is carried on the balance sheet at a value not to exceed the original carrying value established at the time it was placed in inventory. This equipment is intended for resale to third parties at current fair market prices. Sale of this equipment is expected to occur in less than one year. This policy does not preclude us from further transferring serviceable equipment to other wells that we operate, on an as-needed basis.
Drilling and completion cost prepayments represent cash expenditures advanced by us to outside operators prior to the commencement of drilling and/or completion operations on a well.
3. Other Non-Current Assets
Other non-current assets at March 31, 2010 and 2009 consisted of the following:
This lease and well equipment inventory, unlike the equipment inventory in Other Current Assets that is held for resale, is intended for use on leases that we operate. This equipment inventory represents well-site production equipment that we own that has either been purchased or has been removed from wells that we operate. When placed in inventory, new equipment is valued at cost and salvaged equipment is valued at prevailing market prices. The inventory is carried at the lower of the original carrying value or fair market value.
Plugging bonds represent Certificates of Deposit furnished by us to third parties who supply plugging bonds to federal and state agencies where we operate wells. These funds are classified as restricted.
4. Accrued Liabilities
Accrued liabilities for the years ended March 31, 2010 and 2009 consisted of the following:
5. Asset Retirement Obligation
We recognize the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated present value of the asset retirement cost is capitalized as part of the carrying amount, and is included in the proved oil and gas properties in the accompanying consolidated balance sheets. We own oil and gas properties that require expenditures to plug and abandon when reserves in the wells are depleted. These future expenditures are recorded in the period the liability is incurred (at the time the wells are drilled and completed or acquired).
The following table summarizes the activity related to our estimate of future asset retirement obligations for the years ended March 31, 2010 and 2009:
Asset retirement expense as recorded in the years ended March 31, 2010 and 2009 represents plugging and abandonment costs in excess of the estimated asset retirement obligation recorded. We based our initial estimates on our knowledge and experience plugging wells in earlier years.
6. Credit Line
Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Effective January 3, 2006, we amended the existing loan agreement to increase the line of credit amount from $1,000,000 to $20,000,000 with a concurrent borrowing base increase from $1,000,000 to $4,000,000. Effective December 31, 2008, the loan agreement was amended again to extend the maturity date of the credit agreement from December 31, 2008 to December 31, 2010. The current interest rate is 6.5% or prime plus one-quarter of one percent (0.25%) whichever is greater, and the addition of an unused commitment fee equal to one-half of one percent (0.50%) per annum on the difference between the outstanding balance and the borrowing base amount.
Under the credit facility, we must maintain certain financial covenants. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. With the December 31, 2008 amendment, the covenant requiring us to maintain a net worth of at least $1,750,000 was replaced with a covenant requiring us to maintain a debt-to-equity ratio less than one. Another covenant obligates us to maintain a current ratio of at least 1:1 inclusive of unused borrowing capacity and exclusive of the current portion of long-term debt. We were in compliance with all covenants at March 31, 2010.
This credit line is collateralized by a significant portion of our oil and gas properties and production, and as of March 31, 2010, there was no outstanding balance on this line of credit. If necessary, we may borrow funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions or pursue other opportunities that might arise.
7. Commitments
Effective March 1, 2008, we relocated to a new 4,000 square foot office space located in downtown Denver, Colorado. The lease agreement is for a five-year term through April 2013 and currently requires base rent payments of approximately $5,853 per month escalating at a rate of approximately $170 at the end of each year. Office rent expense was approximately $107,000 in 2010 (including building maintenance charges), and $87,000 in 2009. We are committed to a total of $281,000 for the five-year term ending April 1, 2013. Prior to expiration of the lease term, we will evaluate the Denver real estate market and the various available options before deciding on where to lease office space after April 2013.
8. Shareholders’ Equity
Preferred Stock. We have 3,000,000 shares of authorized preferred stock that can be issued in such series and preferences as determined by the Board of Directors.
Stock Option Plan. Effective July 27, 1995, our shareholders approved the 1995 Incentive Stock Option Plan (“the Plan”) authorizing option grants to employees and outside directors to purchase up to 1,000,000 shares of our common stock. The Plan was structured as a 10-year plan and, as such, ended on July 26, 2005. During the Plan’s existence, a total of 665,000 options were granted; of this amount, 50,000 options expired unexercised, 590,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share and the remaining 25,000 options were exercised as of March 31, 2009.
A summary of the status of our stock option plan and outstanding options as of March 31, 2010 and 2009, and changes during the years ended on those dates is presented below:
Since all options are fully vested, and the plan has expired, we will have no stock-based compensation expense related to stock options in future periods unless a new plan is adopted and additional options are granted.
Director Stock Compensation. On March 8, 2007, the Board of Directors adopted a Director Compensation Plan. In connection with this plan, an annual stock grant equal to $36,000 is awarded to each independent director. The number of shares included in each grant is calculated based upon the average closing price of the ten trading days preceding each April 1st anniversary date.
9. Income Tax
Our provision for income taxes for the years ended March 31, 2010 and 2009 comprised of the following:
A reconciliation between the income tax provision at the statutory rate on income taxes and the income tax provision for the years ended March 31, 2010 and 2009 is as follows:
The components of the net deferred tax assets and liabilities for the years ended March 31, 2010 and 2009 are as follows:
We follow authoritative guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements. Tax positions must meet a “more-likely-than-not” recognition threshold before a benefit is recognized in the financial statements. As of March 31, 2010, the Company has not recorded a liability for uncertain tax positions. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. No interest and penalties related to uncertain tax positions were accrued at March 31, 2010. The tax years remaining subject to examination by tax authorities are fiscal years 2005 through 2009.
10. Related Party Transactions
It is our policy that officers or directors may assign to us or receive assignments from us in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. It is also our policy that officers or directors and the Company may participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by non-related third parties. In 2010, Ray Singleton, President of the Company, participated in the drilling of the Crown 41-31 in Sheridan County, Montana on the same terms and conditions as other third parties. The well resulted in a dry hole. During 2010 and 2009, none of our other directors or officer participated with the Company in any of our oil and gas transactions. In prior years, Mr. Singleton has participated with us in the acquisition of producing properties on the same terms and conditions as the Company and other third parties. As such, Mr. Singleton paid for his proportionate share of the acquisition costs at the time of the acquisition. With respect to his working interest in the four producing wells in which he currently has an ownership, at March 31, 2010, the Company had a balance due to Mr. Singleton for approximately $10,000 compared to a payable balance due from him of less than $1,000 at March 31, 2009. This was due to his share of oil and gas revenue exceeding the amount due from him for his share of operating expenses from these wells.
11. Oil and Gas Property
The aggregate amount of capitalized costs related to oil and gas properties and the aggregate amount of related accumulated depreciation and depletion at March 31, 2010 and 2009 are as follows:
Costs directly associated with the acquisition and evaluation of unproved property are excluded from the full cost pool depreciation, depletion and amortization computation until the properties can be classified as proved. These costs have been incurred over the last five fiscal years and are not yet evaluated as proved. Upon proving these properties the costs will be reclassified as proved property, or in the event that a decision is made to cease operations on the property without further work estimated to be performed, the costs will be removed from unproved property and included in the full cost pool to be amortized. Primarily, these costs relate to the following properties:
Williston Basin. Five new wells in the Williston Basin primarily within McKenzie County, North Dakota represent $763,000 for 49.1% of the total unproved property costs. These wells will be removed from the unproved property classification upon evaluation.
Banks Field. The Banks Field represents approximately 20.5% of total unproved property costs, $318,000, associated with a 13,000 gross acre horizontal Bakken play in McKenzie County, North Dakota.
Christmas Meadows. The Christmas Meadows prospect consists of approximately 25.5% of total unproved property costs, $396,000, related to 40,000+ acres operated by Double Eagle Petroleum Company.
The following table shows, by category and date incurred, the oil and gas property costs applicable to unproved property that were excluded from the depreciation and depletion computation at March 31, 2010:
Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2010 and 2009 are summarized as follows:
12. Unaudited Oil and Gas Reserves Information
At March 31, 2010 and 2009, 93% and 98% respectively, of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm Ryder Scott Company. The remaining 7% and 2% of the reserve estimates, respectively, were prepared internally by our management. There are many inherent uncertainties in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available, and these changes could be material.
Proved oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered through wells yet to be completed.
Analysis of Changes in Proved Reserves. Estimated quantities of proved developed reserves (all of which are located within the United States), as well as the changes in proved developed reserves during the periods indicated, are presented in the following tables:
Proved Reserves
(1)
Revisions of Previous Estimates - Overall our properties experienced an increase in estimated economic life due to increases in oil and gas prices during the year ended March 31, 2010. Changes in performance constitute less than 10% of the total amount of revisions of previous estimates.
(2)
Extensions and Discoveries - The additions consisted of two new well in wells in Weld County, Colorado and one new well in the Dunn County, North Dakota.
(3)
Production - This change in reserves is due to volumes of oil and gas that was produced and removed from reserves during the year.
The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to our proved oil and gas reserves. Estimated future cash inflows were computed by applying the 12 month average price of oil and gas on the first day of each month (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves at March 31, 2010, 2009 and 2008. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.
Standardized Measure of Estimated Discounted Future Net Cash Flows
The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for 2010, 2009 and 2008.
Changes in Standardized Measure of Estimated Discounted Net Cash Flows
ITEM 9
ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A
ITEM 9A
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the phrase “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 Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.
We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2010. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Principal Accounting Officer. Based on this evaluation, our Chief Executive Officer and Principal Accounting Officer concluded that, as of March 31, 2010, 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 our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management's Annual Report on Internal Control Over Financial Reporting
The management of Earthstone Energy, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Our internal control over financial reporting includes those policies and procedures that;
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the directors of the Company; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Principal Accounting Officer, we conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework and criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of March 31, 2010.
Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report on Form 10-K. Therefore, this Annual Report on Form 10-K does not include such an attestation.
ITEM 9B
ITEM 9B
OTHER INFORMATION
None.
Part III
ITEM 10
ITEM 10
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in this report.
ITEM 11
ITEM 11
EXECUTIVE COMPENSATION
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in this report.
ITEM 12
ITEM 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in this report.
ITEM 13
ITEM 13
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
AND DIRECTOR INDEPENDENCE
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in this report.
ITEM 14
ITEM 14
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in this report.
Part IV
ITEM 15
ITEM 15
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Exhibit No.
Document
3(i)a
Restated Certificate of Incorporation of Earthstone Energy, Inc., effective May 12, 1981, as amended by (i) Certificate of Amendment of Certificate of Incorporation, effective November 20, 1986; (ii) Certificate of Amendment of Certificate of Incorporation, effective July 1, 1996; and (iii) Certificate of Designations of Series A Junior Participating Preferred Stock, effective February 5, 2009, incorporated by reference to Exhibit 3(i) of our Quarterly Report on Form 10-Q for the quarter ended December 31, 2009, filed with the SEC on February 17, 2009.
3(i)b
Amended and Restated Certificate of Incorporation as approved by stockholders of the Company at the Company’s 2009 Annual Meeting of Stockholders and the amendments to the Company’s Certificate of Incorporation previously disclosed in the Company’s proxy statement on Schedule 14A filed with the Securities and Exchange Commission on November 5, 2009, incorporated by reference to Exhibit 3(i) on Form 8-K filed with the SEC on March 3, 2010.
3(ii)a
Bylaws of Earthstone Energy, Inc., dated July 15, 1986, as amended by First Amendment to Bylaws, dated February 4, 2009, incorporated by reference to Exhibit 3(ii) of our Quarterly Report on Form 10-Q for the quarter ended December 31, 2009, filed with the SEC on February 17, 2009.
3(ii)b
Amended and Restated Bylaws reflecting recent changes made to the Company’s Certificate of Incorporation to remove certain outdated and redundant provisions that existed in our prior bylaws with respect to corporate governance, stockholder and director meeting procedures, and indemnification procedures. Changes to the bylaws include, among other things: (i) amendments to reflect the new name of the Company; (ii) expansion of certain provisions with respect to stockholders’ meetings and record dates; (iii) amendments in respect of corporate governance, board committees, and board meetings; (iv) amendments to certain provisions in respect of officers and their duties; (v) amendments to certain provisions in respect of share certificates; and (vi) removal of indemnification provisions are incorporated by reference to Exhibit 3(ii) on Form 8-K filed with the SEC on March 3, 2010.
4.1
Rights Agreement, dated February 4, 2009, between Earthstone Energy, Inc. and Corporate Stock Transfer, Inc., incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K., filed with the SEC on February 5, 2009.
10.1*
Oil and Gas Incentive Compensation Plan, dated April 1, 1980, as amended, incorporated by reference to our Annual Report on Form 10-K for the fiscal year ended March 31, 1985, filed with the SEC.
Exhibit No.
Document
10.2
Loan Agreement, dated March 4, 2002, between The Bank of Cherry Creek and Earthstone, incorporated by reference to Exhibit 10(i)a of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2002, filed with the SEC on June 28, 2002; as amended by Amended Loan Agreement, dated January 3, 2006, between American National Bank (formerly The Bank of Cherry Creek) and Earthstone, incorporated by reference to Exhibit 10(i)a of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2006, filed with the SEC on July 14, 2006; and as further amended by Amended Loan Agreement, dated December 31, 2006, between American National Bank and Earthstone, incorporated by reference to Exhibit 10(i)a of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2009, filed with the SEC on June 29, 2007.
10.3*
Performance Bonus Plan, dated effective April 1, 2007, incorporated by reference to Exhibit 10.3 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
10.4*
Director Compensation Plan, dated effective April 1, 2007, incorporated by reference to Exhibit 10.4 of our Amended 10-K/A, filed with the SEC on October 9, 2009 as amended by board resolution dated March 31, 2010, filed herewith.
10.5*
Form of Restricted Stock Agreement pursuant to the Director Compensation Plan, incorporated by reference to Exhibit 10(ii) of the Annual Report on Form 10-KSB for the fiscal year ended March 31, 2008, filed with the SEC on July 11, 2008.
10.6*
Part-Time Employment and Confidentiality Agreement, effective March 31,2008, between Joseph Young and Earthstone, incorporated by reference to Exhibit 10.6 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
14.1
Code of Business Conduct and Ethics, incorporated by reference to Exhibit 14.1 of our Annual Report on Form 10-KSB/A for the fiscal year ended March 31, 2004, filed with the SEC on May 11, 2005.
16.1
Letter Regarding Change in Certifying Accountant, incorporated herein by reference to Exhibit 16.1 of our Current Report on Form 8-K, filed with the SEC on July 21, 2008.
List of Subsidiaries of Earthstone, incorporated by reference to Exhibit 21 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
31.1
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
31.2
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer)
32.1
Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
32.2
Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer).
99.1
Nominating Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.1 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
99.2
Compensation Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.2 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
99.3
Report of Ryder Scott Company filed herewith.
*
Indicates management contracts or compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15 of Form 10-K.
Signatures
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.
Date
By: /s/ Ray Singleton
June 18, 2010
Ray Singleton, President
By: /s/ Joseph Young
June 18, 2010
Joseph Young,
Principal Accounting Officer
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.
Name and Capacity
Date
By: /s/ Ray Singleton
June 18, 2010
Ray Singleton, Director
By: /s/ Richard K. Rodgers
June 18, 2010
Richard K. Rodgers, Director and
Compensation Committee Chairman
By: /s/ Monroe W. Robertson
June 18, 2010
Monroe W. Robertson, Director and
Audit Committee Chairman