ITEM 1
DESCRIPTION OF BUSINESS
Overview
Earthstone Energy, Inc. was incorporated in Delaware in 1969 as Basic Earth Science Systems, Inc. We changed our name in 2010 to Earthstone Energy, Inc. Earthstone Energy, Inc. (“Earthstone” or “the Company” or “we” or “our” or “us”) is a growth-oriented independent oil and gas exploration and production company primarily engaged in the exploration, development and production of oil and natural gas properties. We have an established production base that generates positive cash flow from operating activities and profits. Our operating activities are concentrated in the North Dakota and Montana portions of the Williston basin, the southern portions of Texas, onshore portions of the Gulf Coast, and the Denver-Julesburg basin of Colorado. As of March 31, 2011, our estimated net proved oil and natural gas reserves were 1,015,000 Bbls of oil and condensate and 735,000 Mcfs of natural gas.
Strategy
Our primary objective is to enhance shareholder wealth by increasing our net asset value, net reserves and cash flow through acquisitions, exploration, development, exploitation, and divestiture of oil and gas properties following a balanced risk strategy.
The four key components of our growth strategy are:
•
Identification and acquisition of strategic and significant producing properties; strategic and significant in that they are either accretive to our existing production or will provide an increase to the Company’s existing production base.
•
Utilization of strategic partners with industry experience in the specific geographic areas for which we desire to expand.
•
Cost effective implementation of internally and externally generated exploration and development drilling projects.
•
Boosting cash flows from existing oil and natural gas production through a combination of cost control and the exploitation of behind-pipe potential.
Our primary operational focus is in the Montana and North Dakota portions of the Williston basin. This oil rich basin has been, and will continue to be, allocated the majority of our capital expenditure budget. We have been involved in the Williston basin since the early 1980’s and only in south Texas does the Company have a longer history. Accordingly, we have a significant understanding of, and exposure to, both the local geology and geologic processes.
The Williston basin and our south Texas waterfloods are primarily oil producing properties. In an effort to expand our reserves and to diversify our portfolio of properties, we have undertaken efforts in other areas, notably, Colorado, Nebraska and onshore portions of the Gulf Coast. Last year, drilling, particularly non-operated drilling projects, comprised the majority of capital expenditures. In the coming year we expect this trend to continue despite our continued emphasis on the acquisition of producing properties. While we expect to drill a considerable number of wells for our size, this effort is primarily to protect expiring leases and maintain our interests under existing acreage holdings. Historically, we have not placed emphasis on acquiring new, large, non-producing acreage positions. In the coming year, as our existing inventory of acreage is developed, we could see the need to shift capital expenditure dollars into undeveloped acreage.
We will be focusing on keeping our operating costs under control, as we expect rig and vendor service costs to continue to escalate due to high demand. Maintaining a low overhead structure is fundamental to our cost containment. However, over the last year we have expanded and/or restructured our staff; primarily to comply with increased SEC regulation. Since our fiscal year end, we have added additional operational staff, and expect to continue to do so, as we increase our capacity to drill more wells. We are using and will continue to use the services of independent consultants and contractors to perform various professional services. We believe that this use of third-party service providers enhances our ability to contain general and administrative expenses.
We caution that the following expectations may be altered by subsequent events or other, more attractive opportunities that may present themselves in the future.
On-Going Activities
Williston Basin. The Williston basin continues to be our highest area of activity, both in terms of cash flow from existing properties and expenditures for drilling efforts as well as the acquisition of producing properties. We have several areas within the Williston basin where we expect drilling operations to commence and/or continue in 2011. These areas are the Banks Field in McKenzie County, North Dakota, the Mondak Field in McKenzie County, North Dakota, the Elm Coulee Field in Richland County, Montana, our acreage in the Indian Hill Field in McKenzie County and our acreage in Divide County, North Dakota and Sheridan County, Montana. While not our primary area of focus, we continue to deploy capital in legacy areas beyond the Williston basin to exploit reserve potential on existing properties.
Banks Field - McKenzie County, North Dakota. Earthstone retains a 6.5% working interest in approximately 13,000 gross (845 net) acres in and around the Banks field. Early efforts on this prospect were less than successful. With improvements in hydraulic stimulation technology, this area is now much more attractive. In the last year, two companies, Zenergy and SM Energy, have drilled five wells on the prospect. Two wells are now on production (the Pederson 10-3H and Fossom 15-35H). At March 31, 2011, three wells (Ceynar 29-32H, A. Johnson 12-1H and Berquist 33-28H) had been drilled, but not yet completed. In addition, we anticipate Brigham to drill ten wells on this acreage before calendar year end and we have already executed AFEs authorizing the drilling of six of the possibly ten wells.
Mondak Field - McKenzie County, North Dakota. The Company has an interest in three wells in the Mondak Field. One of these wells was drilled in the year ended March 31, 2011. This well, the Mondak Federal 24X-12, is still being completed and not yet on production. This acreage is currently developed for one well per spacing unit. However, we anticipate that this acreage will be developed for two wells per spacing unit in the future.
Elm Coulee Field - Richland County, Montana. The Company has an interest in four horizontal Bakken wells in the Elm Coulee Field and several, legacy, vertical wells that hold Bakken acreage. Most areas in the Elm Coulee Field contain two wells per spacing unit. Now that this field is reaching maturity, it is not unreasonable to expect select areas of this field to be developed with three wells per spacing unit. We believe it is likely that this will occur in the coming year.
Indian Hill Field - McKenzie County, North Dakota. The Company holds approximately 960 gross (192 net) acres in the Indian Hill Field. With improving hydraulic stimulation technology, a number of Bakken horizontal wells have been drilled in the area. We anticipate that this acreage will be proposed for horizontal Bakken development in the coming year.
Divide County, North Dakota - Sheridan County, Montana. Recently, several companies have drilled in these two counties in the Bakken Shale, resulting in strong production figures. Also in the third and fourth quarter of this year, we acquired a 26.5% working interest in five producing wells and a 25% interest in a shut-in well in Sheridan County, Montana. By virtue of these acquisitions, in addition to the legacy producing properties in these two counties, along with undeveloped leasehold acreage, the Company has an estimated 15,200 gross (4,000 net) acres which could be evaluated for horizontal Bakken development in the coming years.
Other Areas
Denver-Julesburg Basin - Weld County, Colorado. As of March 31, 2010, we had finished the first and second phase of our project to (1) drill and complete sixteen new down-spaced wells on the Antenna Federal property in Weld County, Colorado and (2) to drill six “edge wells” around this property. All development work on the phase one and two on this 640 acre section has been finalized. During the year ended March 31, 2011, we recompleted nine of the existing Codell wells into the J-Sand formation. Kerr-McGee Oil & Gas Onshore, LP is the operator of this project.
Reserves
During the year ended March 31, 2011, our proved reserves in BOE and PV-10 increased approximately 17% and 42%, respectively (from March 31, 2010). Additional information about our reserves and the calculation of reserves may be referenced in Item 2. “Properties.”
Contemplated Activities
We are continually evaluating other drilling and acquisition opportunities for possible participation. The absence of news and/or press releases should not be interpreted as a lack of development or activity. Generally, at any one time, we are engaged in various stages of evaluation in connection with one or more drilling or acquisition opportunities. Unless required by applicable law, our policy is generally to not disclose the specifics of any such opportunity until such time as that transaction is finalized and we have entered into a definitive agreement regarding the same and then, only when such transaction is material to our business. Similarly, we do not speculate on the outcome of such ventures until the drilling, production or other results are available and have been verified by us.
We may alter or vary all or part of these contemplated activities based upon changes in circumstances, including, but not limited to, unforeseen opportunities, inability to negotiate favorable acquisitions, farmouts, joint ventures, or divestitures, commodity prices, lack of cash flow, lack of funding and/or other events which we are not able to anticipate.
Segment Information and Major Customers
Industry segment. We are engaged only in the upstream segment of the oil and gas industry, which comprises exploration, production, and development for and of crude oil and natural gas. While we operate a small number of oil wells, we do not own or operate any gas gathering or processing plant facilities nor do we possess sufficient volume on any pipeline to market our product to end users. All of our operations are conducted in the United States. Consequently, we presently report under a single industry segment.
Markets. We are a small company and, as such, have no impact on the market for our product and little control over the price received. Markets for crude oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including other sources of production, competitive fuels and proximity and capacity of pipelines or other means of transportation, seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. Substantially all of our natural gas production is sold at prevailing wellhead gas prices, subject to additional charges customary to an area.
The oil and gas business is not generally seasonal in nature, although unusual weather extremes for extended periods may increase or decrease demand for oil and natural gas products temporarily. Additionally, catastrophic events, such as hurricanes or other supply disruptions, may also temporarily increase the demand for oil and gas supplies from areas unaffected by supply disruptions. Such events and their impacts on oil and gas commodity prices may cause fluctuations in quarterly or annual revenue and earnings. Also, because of the location of many of our properties in Montana and North Dakota, severe weather conditions, especially in the winter months, could have a material adverse effect on our operations and cash flow.
Major Customers. During the year ended March 31, 2011, approximately 48% of our oil and natural gas production revenues were received from sales to nine purchasers (compared to 43% to six purchasers in the previous fiscal year). The remaining 52% of our revenue was received from non-operated properties where we have no direct contact with the purchaser. On these properties our portion of the product is marketed on our behalf by the 23 different companies who operate these wells. These 23 companies may, unbeknownst to us, market to one or more of the same purchasers to whom we sell directly. 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 these purchasers, or purchasers on non-operated properties, it has been estimated that the reduction in annual revenue would be less than 10%. It is not expected that the loss of any one of these purchasers would cause a material adverse impact on the Company’s results from operations, as alternative markets for oil and natural gas production are readily available. Should we require a new buyer of our production, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.
Competition
The oil and gas industry is a highly competitive and speculative business. We encounter strong competition from major and independent oil companies in all phases of our operations. In this arena, we must compete with many companies having financial resources and technical staffs significantly larger than our own. Furthermore, having pursued an acquisition strategy for over a decade, we did not develop an in-house geologic or geophysical infrastructure, as have many of our competitors. Rather than incur the time and expense to develop in-house capability, we chose to enter joint ventures with other companies having such resources to accelerate our efforts. Competition is intense with respect to acquisitions and the purchase of large producing properties. Due to the limited capital resources available to us, we have historically focused on smaller and/or marginal properties with behind-pipe potential in our acquisition efforts. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.
Employees
As of March 31, 2011, we had eight full-time, two part-time employees and two part-time contractors. Four of these employees are primarily field laborers and are located at our subsidiary’s (Basic Petroleum Services, Inc.) field office in Bruni, Texas, forty-five miles southeast of Laredo, Texas. In addition, in other areas, we have seven contract field workers on a part-time retainer basis. We believe our employee and contractor relations are good.
Regulations
General. Our company is affected in varying degrees by federal, state, regional and local laws and regulations, including, but not limited to, laws governing well spacing, air emissions, water discharges, reporting requirements, endangered species, marketing, prices, taxes, allowable rates of production and the plugging and abandonment of wells, the subsequent rehabilitation of the well site locations, occupational health and safety, control of toxic substances, and other matters involving environmental protection. These laws are continually changing and, in general, are becoming more restrictive. We have expended, and expect to expend in the future, significant funds to comply with such laws and regulations. Changes to current local, state or federal laws and regulations in the jurisdictions where we operate could require additional capital expenditures and result in an increase in our costs. Although we are unable to predict what additional legislation, if any, might be proposed or enacted, additional regulatory requirements could impact the economics of our projects.
Environmental matters. We are subject to various federal, state, regional and local laws and regulations related to the discharge of materials into, and the protection of, the environment. These laws and regulations, among other things, may impose a liability on the owner or the lessee for the cost of pollution cleanup resulting from operations, subject the owner or lessee to a liability for pollution damages, require the suspension or cessation of operations in affected areas and impose restrictions on injection into subsurface formations in order to prevent the contamination of ground water. All but three of the disposal wells that we utilize are owned and operated by third parties whose disposal practices are outside of our control. With respect to the three disposal wells that we own and operate, we currently use these facilities only for the disposal of produced water from other Company-operated properties. Although environmental requirements do have a substantial impact upon the energy industry, these requirements do not appear to affect us any differently than other companies in this industry who operate in a given geographic area. We are not aware of any environmental claims which could have a material impact upon our financial condition, results of operations, or cash flows. Such regulations have increased the resources required and costs associated with planning, designing, drilling, operating and both installing and abandoning oil and natural gas wells and facilities. We maintain insurance coverage that we believe is customary in the industry.
Available Information
We make available on our website, earthstoneenergy.com, under “Investor Relations, SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file or furnish them to the U.S. Securities and Exchange Commission (“SEC”).
Our Code of Business Conduct and Ethics, Board of Directors Committee Charters (Audit, Nominating, and Compensation Committees), and Whistleblower Policy are also available on our website under “Investor Relations, Corporate Governance.”
ITEM 1A
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
As of March 31, 2011, we owned a working interest in 83 gross producing oil wells and 44 gross producing gas wells in six states: North Dakota, Montana, Colorado, Texas, Louisiana and Wyoming.
Productive Wells
Production
Specific production data relative to our oil and natural 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
As of March 31, 2011, our estimated proved developed and undeveloped oil and natural gas reserves in barrels of oil equivalent (“BOE”) was 1,137,000, a 17% increase from the prior year end’s estimated proved oil and natural gas reserves of 970,000 BOE. This increase primarily reflects the addition of new wells, along with an increase in the life of existing wells due to an increase in oil and natural gas prices.
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 onshore south Texas. The following table summarizes the estimated proved developed and undeveloped oil and natural gas reserves divided between operated and non-operated properties for these three areas as of March 31, 2011:
Estimated Proved Oil and Gas Reserves by Area
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 natural gas reserves have been estimated as of March 31, 2011, 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 91% and 93% of the PV-10 of our oil and gas reserves as of March 31, 2011 and 2010, 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. The office of Ryder Scott that prepared our reserve estimate is registered in the state of Texas (License #F-1580). Ryder Scott prepared our reserves estimates based upon a review of property interests being appraised, historical production, lease operating expenses and price differentials for our wells. Additionally, authorizations for expenditure ("AFEs"), geological and geophysical data, and other engineering data that complies with SEC guidelines are among that which we provide to such engineer for consideration in estimating our underground accumulations of crude oil and natural gas. This information was reviewed by Ray Singleton, our President and Chief Executive Officer, to ensure accuracy and completeness of the data prior to and after submission to Ryder Scott. 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. The report of Ryder Scott dated May 6, 2011, 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 24 of our 127 producing properties because of their relatively low values. Instead, reserves for these properties were prepared by in-house personnel and contributed 9% and 7% to our reserves as of March 31, 2011 and 2010, respectively. Internal reserve estimates were prepared by Ray Singleton, President and Chief Executive Officer, whose qualifications are summarized above.
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.
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 reserves 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, 2011. All of our reserves are located in the United States.
Estimated Proved Developed and Undeveloped Oil and Gas 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 on Form 10-K. In addition, estimates of proved reserves are subject to revision to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based.
Additional information pertaining to our proved reserves is set forth under the heading "Unaudited Oil and Gas Reserves Information" in the notes to the consolidated financial statements included later in this Annual Report on Form 10-K.
Proved Undeveloped Reserves
As of March 31, 2011, we had no proved undeveloped reserves.
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 years ended March 31, 2011 and 2010.
Drilling Activities
The following table sets forth our gross and net working interests in exploratory and development wells drilled during the years ended March 31, 2011, 2010, and 2009, respectively:
Exploratory and Developmental Wells Drilled
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
Field Service Equipment
As of March 31, 2011, 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 $6,000 per month plus maintenance fees 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 6 to the consolidated financial statements.
ITEM 3
ITEM 3
LEGAL PROCEEDINGS
None.
Part II
ITEM 5
ITEM 5
MARKET FOR REGISTRANT’S COMMON EQUITY,
RELATED SHAREHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Price Range of Common Stock, Number of Holders and Dividend Policy
Effective December 31, 2010, the Board of Directors authorized and effected a 1-for-10 reverse stock split which converted ten (10) shares of the Company’s common stock into one (1) share of common stock. All following references to the number of common shares, treasury shares, and per share amounts reflect the reverse stock split.
Our common stock is currently quoted on the NASDAQ Global Select Market under the ticker symbol “ESTE.” Prior to January 26, 2011, our stock was traded on the Over-the-Counter Bulletin Board (“OTCBB”) under the symbol “BSIC.”
The closing bid price on NASDAQ of our common stock on June 10, 2011, was $14.14. The following table sets forth the quarterly high and low sales prices of our common stock as reported on NASDAQ for the period from January 26, 2011 through March 31, 2011:
¹
Our common stock commenced trading on NASDAQ on January 26, 2011.
The following table sets forth the range of high and low bid quotations of 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.
¹
Our common stock commenced trading on NASDAQ on January 26, 2011.
As of June 10, 2011, we had approximately 1,964 shareholders of record. We have never paid a cash dividend on our common stock. 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 March 31, 2011.
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 shares having a fair market value equal to $36,000 on April 1 of each year as further described below. 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.
The Plan allows up to 50,728 shares of the Company’s common stock to be issued to directors under the Plan, subject to certain restrictions and vesting, of which 9,270 shares were granted during the year ended March 31, 2011, for a total of 30,012 shares that have been granted as of March 31, 2011. Accordingly, as of the year ended March 31, 2011, 20,716 shares of common stock remain available for issuance under the Plan.
Grants of shares of restricted stock vest one-third each year over three years. 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 March 31, 2011, for each non-employee director was as follows: Robertson - 8,555 shares; Rodgers - 8,555; and Calerich - 552.
In addition, on April 1, 2011, each of the three non-employee directors was granted 1,867 shares of restricted stock on April 1, 2011, subject to vesting and forfeiture, resulting in 15,115 shares of common stock remaining available for issuance under the Plan as of June 10, 2011. All restricted shares are considered issued and outstanding shares of the Company’s common stock at the grant date and have the same dividend and voting rights as other common stock.
Purchases of Equity Securities
The following summarizes monthly share repurchase activity for the fourth quarter of the year ended March 31, 2011:
¹
On October 22, 2008, the Company’s Board of Directors authorized a share buyback program for the Company to repurchase up to 50,000 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 150,000. 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, 2011, 10,997 shares were repurchased under the share buyback program and 109,440 shares remain available for future repurchase.
ITEM 6
ITEM 6
SELECTED FINANCIAL DATA
As a “smaller reporting company,” we are not required to provide this information.
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.
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, 2011 and 2010, 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. As of March 31, 2011, we had a working capital surplus of $4,930,000 (a current ratio of 3.96:1) compared to a working capital surplus as of March 31, 2010 of $5,062,000 (a current ratio of 3.53:1). The increase in current ratio is primarily a result of the timing between payments made for payables, cash received for revenue and joint interest billings and the timing and use of prepaid balances in addition to the use of cash for the acquisition, development and exploration of oil and gas properties.
Cash Flow. Cash provided by operating activities decreased 2% from $2,666,000 for the year ended March 31, 2010 to $2,624,000 for the year ended March 31, 2011. This change related primarily to the timing and collection of accounts receivable, the timing and payment of accounts payable and accrued liabilities, and the application of prepaid balances.
Net cash used in investing activities more than doubled from the previous year from $1,641,000 for the year ended March 31, 2010 to $3,356,000 for the year ended March 31, 2011, which relates primarily to our drilling and completion activities during the year. The difference relates primarily to expenditures made during the year ended March 31, 2011, on an acquisition of producing properties, new horizontal Bakken wells in the Williston basin, the recompletion of D-J basin wells in Colorado and on additional acreage.
Net cash used in financing activities was nearly half of that of the pervious year. During the year ended March 31, 2010, $208,000 was used to purchase treasury shares, while $122,000 was utilized for treasury share acquisition for the year ended March 31, 2011. The Company’s share buyback program was adopted in October 2008 and will terminate in October 2011, 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, 2011, we spent $2,729,000 on various projects. This compares to $2,156,000 for the year ended March 31, 2010. During the year ended March 31, 2011, capital expenditures were comprised of acquisitions (47%), drilling and completions (46%) and leasehold (7%). Approximately half of capital expenditures occurred in the Williston basin where funds were spent on the purchase of producing wells, new wells drilled within the Bakken development area and additional leasehold acreage. Approximately 20% of expenditures were spent on drilling and recompletion in the D-J 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, 2011, we have AFEs totaling $588,000 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.
Divestitures/Abandonments
We sold five wells and plugged eight wells during the year ended March 31, 2011.
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.
Results of Operations
Selected Financial Information
The following provides selected financial information and averages for the years ended March 31, 2011 and 2010. Certain prior year amounts may have been reclassified to conform to the current presentation.
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, 2011, this revenue amount is net of $107,000 in well service and water disposal revenue, which would otherwise total $8,206,000 in revenue for the year ended March 31 2011, compared to $50,000 to total $7,269,000 for the year ended March 31, 2010.
Overall lifting cost (oil and gas production expenses and production taxes)
Averages calculated based upon non-rounded figures
The Year Ended March 31, 2011 Compared with the Year Ended March 31, 2010
Overview. Net income for the year ended March 31, 2011, was $1,602,000 compared to net income of $1,028,000 for the year ended March 31, 2010, a 56% increase. The increase in sales prices, as offset by a decline in sales volumes and increase in production costs, resulted in the increase in net income. While overall production expenses increased as compared to these expenses for the year ended March 31, 2010, general and administrative expenses declined when compared to the year ended March 31, 2010.
Revenues. Oil and natural gas sales revenue increased $880,000 (12%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010, primarily due to higher realized oil and gas prices per barrel of oil equivalent (“BOE”), as offset by reduced sales volumes.
Volumes and Prices. On an equivalent barrel basis, sales decreased 11% from 137,000 BOE for the year ended March 31, 2010 to 122,000 BOE for the year ended March 31, 2011.
Oil sales volumes decreased 5% from 98,865 barrels for the year ended March 31, 2010 to 93,613 barrels for the year ended March 31, 2011, while the average price per barrel increased 18% from $62.94 for the year ended March 31, 2010 to $74.06 for the year ended March 31, 2011. The decrease in volumes was primarily related to production declines on two wells; the Halvorsen 31X-36 in the Williston basin and the USA 4-36 in the D-J basin. These two wells, both newly drilled in 2009, contributed high initial production for the year ended March 31, 2009. As anticipated, during the year ended March 31, 2011, these two wells exhibited steep, but normal initial declines; thereby reducing oil sales by approximately 4,731 barrels from the year ended March 31, 2010. To a lesser extent, for the reasons detailed in the paragraph below, oil volumes in the D-J basin reported in our Form 10-K for the year ended March 31, 2010 were not representative of normal oil sales. Oil sales from these wells were approximately 1,200 barrels higher than actual volumes sold in the period.
Natural gas sales volumes decreased 24% from 228,575 Mcf for the year ended March 31, 2010 to 172,386 Mcf for the year ended March 31, 2011, while the average price per Mcf increased 55%, from $4.36 for the year ended March 31, 2010 to $6.76 for the year ended March 31, 2011. This apparent decline in gas sales volume was attributable to the reporting for the year ended March 31, 2010 a portion of gas volumes for the year ended March 31, 2009 due to inaccurate estimates at the close of the year ended March 31, 2009. In March 2010, we received and reported in our Form 10-K for the year ended March 31, 2010, gas sales that exceeded our previous accrued estimates of gas sales from periods back to April 2008. From April 2008 to September 2009, the operator of our D-J basin wells was in the midst of an accounting system conversion and furnished us with minimal data. In those prior periods, we estimated and accrued gas sales based on the information available at the time. Had accurate information on gas sales been available and reported in those prior periods, our reported gas sales volumes in our Form 10-K for the year ended March 31, 2010, would have been lower than those reported. Excluding the volumes reported for the year ended March 31, 2010 that pertained to prior periods, gas sales volumes for the two most current years were comparable.
Production Expenses. Production expenses are comprised of the following items:
Oil and natural gas production expense increased $585,000 (20%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010. The two principal components of oil and gas production expense are 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 expense from period to period.
Workover expense increased $404,000 (89%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010. This increase is primarily attributable to operations in the West Texas waterflood fields. Routine lease operating expense also increased $194,000 (12%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010. Production taxes, which are a function of sales revenue, increased $88,000 for the year ended March 31, 2011, as compared to the year ended March 31, 2010. Production taxes as a percent of oil and natural gas sales revenue remained steady at 7%.
The increase in the production expenses as described above were offset by the $101,000 (32%) decrease in transportation costs for the year ended March 31, 2011, as compared to the year ended March 31, 2010, as production was lower for the year ended March 31, 2011. The decline in production resulting in the decrease in transportation costs was nominally offset by such costs increasing for the industry during 2011.
The overall lifting cost (oil and natural gas production expense plus production taxes) per BOE increased 34% from $21.48 for the year ended March 31, 2010 to $28.83 for the year ended March 31, 2011. The increase primarily related to this increase in workover costs as 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 $56,000 (5%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010 due to the reduction in production. Depletion expense per BOE increased from $8.65 for the year ended March 31, 2010 to $9.24 for the year ended March 31, 2011.
General and administrative ("G&A") expense decreased $264,000 (15%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010. This decrease was primarily due to reductions in professional fees, which included investor relations costs, legal fees, accounting fees and Sarbanes-Oxley expenses. As a percent of total sales revenue, G&A expense decreased from 24% for the year ended March 31, 2010 to 18% for the year ended March 31, 2011, as a result of greater revenues and cost reductions. G&A expense per BOE decreased 5% from $12.99 for the year ended March 31, 2010 to $12.38 for the year ended March 31, 2011.
Income Taxes. For the year ended March 31, 2011, we recorded income tax expense of $206,000. This amount consisted of a current period expense of $104,000, and deferred tax expense of $102,000. Our effective income tax rate decreased from 12.57% for the year ended March 31, 2010 to 11.41% for the year ended March 31, 2011. Our effective income tax rate was lower for the year ended March 31, 2011, primarily due to an increase in deferred tax assets from the amounts originally estimated on the prior year tax provision.
Critical Accounting Policies and Estimates
See Note 1 to the consolidated financial statements.
Recent Accounting Pronouncements
In December 2008, the SEC decreed modified instructions for reporting oil and gas activities. The rule, effective and adopted for the Company’s year ended March 31, 2010, changes the oil and natural gas prices used to calculate reserve quantities and the full cost ceiling limitation from the spot price on the last day of the reporting period to the 12 month average prices, calculated as the unweighted arithmetic average price of oil and gas on the first day of each month for each of the 12 months prior to the last day of the reporting period (unless prices are defined by contractual arrangements). Adoption of this rule impacted depletion expense for the year ended March 31, 2010, as well as the ceiling test calculation for oil and gas properties as of March 31, 2010. Adoption of this rule for the year ended March 31, 2010 is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of this guidance, other than pricing, significantly impacted the financial statements, and it is impracticable to estimate the effect of applying the new rule on net income or the amount recorded for depletion for the year ended March 31, 2010.
In January 2010, the Financial Accounting Standards Board expanded the required disclosure of fair value measurements, requiring disclosure of the amounts and reasons for significant transfers between Level 1 and Level 2 of the fair value hierarchy, and disaggregation in the reconciliation for fair value measurements using significant unobservable inputs to separately provide information about purchases, sales, issuances and settlements. Effective for the Company’s year ended March 31, 2010, additional disclosure is also required about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring measurements. Adoption of this amendment, which solely amends disclosure requirements, results in no impact to the Company’s financial position, results of operations, or cash flows.
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.
ITEM 7A
ITEM 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
As a “smaller reporting company,” we are not required to provide the information.
ITEM 8
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Earthstone Energy, Inc.
Consolidated Financial Statements
and Accompanying Notes
March 31, 2011 and 2010
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, 2011 and 2010, and the related statements of operations, shareholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 audits 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Earthstone Energy, Inc. as of March 31, 2011 and 2010, and the results of their operations and their cash flows for the years then ended 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 and the ceiling test calculation for oil and gas property.
/s/ Ehrhardt Keefe Steiner & Hottman PC
Denver, Colorado
June 15, 2011
Earthstone Energy, Inc.
Consolidated Balance Sheets
Page 1 of 2
See accompanying notes to consolidated financial statements.
Earthstone Energy, Inc.
Consolidated Balance Sheets
Page 2 of 2
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, 2011 and 2010
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
March 31, 2011
1. Summary of Significant Accounting Policies
Organization and Nature of Operations. Earthstone Energy, Inc. was originally organized in July 1969 as Basic Earth Science Systems, Inc. and changed its name in 2010 to Earthstone Energy, Inc. The Company is principally engaged in the acquisition, exploration, development, and production of crude oil and natural gas properties, primarily operating in 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 the accounts of Earthstone Energy, Inc. and its wholly-owned subsidiary. All significant intercompany accounts and transactions have been eliminated. The Company does not have any unconsolidated special purpose entities.
At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Earthstone Energy, Inc. and its wholly-owned subsidiary. When such terms are used in this manner throughout this document they are in reference only to the corporation, Earthstone Energy, Inc. and its subsidiaries, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.
Basis of Presentation. The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP").
Oil and Gas Sales. We derive revenue primarily from the sale of produced natural gas and crude oil. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's interest. Revenues are reported 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 and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between 30 and 90 days after the date of production. Estimates of the amount of production delivered to purchasers and the prices at which it was delivered are necessary at year end. Management’s knowledge of the Company’s properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors are 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 Reserves. Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate 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 the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.
Oil and Gas Property. The Company uses the full cost method of accounting for costs related to its oil and gas property. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition and exploration activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas property unless nonrecognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.
Capitalized costs are subject to a ceiling test, as prescribed by Securities and Exchange Commission (“SEC”) regulations, that limits such pooled costs to the aggregate of the present value of future net cash flows attributable to proved oil and gas reserves, less future cash outflows associated with the asset retirement obligation that have been accrued plus the lower of cost or estimated fair value of unproved properties not being amortized less any associated tax effects. Prices are held constant for the productive life of each well. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, the excess is reflected as a non-cash charge to earnings. The write-down is permanent and not reversible in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase the ceiling amount. As of the balance sheet date, capitalized costs did not exceed the ceiling test limit.
For the years ended March 31, 2011 and 2010, the oil and natural gas prices used to calculate the full cost ceiling limitation are the 12 month average prices, calculated as the unweighted arithmetic average price of oil and gas on the first day of each month for each of the 12 months prior to the last day of the reporting period (unless prices are defined by contractual arrangements) and net cash flows are discounted at 10 percent.
Prior to March 31, 2010, ceiling calculations were based on the spot price on the last day of the reporting period. This change is a result of SEC requirements for reporting oil and gas activities effective for annual reporting periods ending on or after December 31, 2009. This rule, titled "Modernization of Oil and Gas Reporting" was implemented by the Company effective March 31, 2010.
Adoption of this rule impacted depletion expense for the year ended March 31, 2010, as well as the ceiling test calculation for oil and gas properties as of March 31, 2010. The rule further impacted the oil and gas reserve quantities that were estimated by the reservoir engineer. Adoption of this rule for the year ended March 31, 2010 is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of this guidance, other than pricing, significantly impacted the financial statements, and it is impracticable to estimate the effect of applying the new rule on net income or the amount recorded for depletion for the year ended March 31, 2010.
Unproved properties are excluded from the ceiling test. Instead, these property costs 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 of oil and gas property, excluding those pertaining to unproved properties, are depleted on a composite units-of-production method based on estimated proved reserves. For depletion purposes, the volume of reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Depletion expense per equivalent barrel of production was $9.24 and $8.65 for the years ended March 31, 2011 and 2010, respectively.
Oil and Gas Production Costs. Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Production costs (also referred to as lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities, and severance taxes.
Asset Retirement Obligation. The Company's activities are subject to various laws and regulations, including legal and contractual obligation to plug, reclaim, remediate, or otherwise restore oil and gas property at the time such asset ceases to be productive. An asset retirement obligation ("ARO") is initially measured at fair value and recorded as a liability with a corresponding asset when incurred if a reasonable estimate of fair value can be made. This is typically when a well is completed or an asset is placed in service. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the full cost pool. Over time, the liability increases for the change in its present value (and accretion expense is recorded), while the capitalized cost decreases by way of depletion of the full cost pool. Estimates are reviewed quarterly and adjusted in the period in which new information results in a change of estimate.
Income Taxes. Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.
No significant uncertain tax positions were identified as of any date on or before March 31, 2011. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of March 31, 2011, the Company has not recognized any interest or penalties related to uncertain tax benefits. For further information, see Note 8 below.
Earnings Per Share. Basic and diluted earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period, after giving effect to the 1-for-10 reverse stock split effective December 31, 2010. As of the balance sheet date, no dilutive securities were outstanding.
Cash and Cash Equivalents. All highly liquid investments with original maturities of ninety days or less are considered to be cash equivalents. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.
Fair Value Measurements. Financial instruments and nonfinancial assets and liabilities, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board, prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities, all of which are considered to be representative of their fair market value, due to the short-term and highly liquid nature of these instruments.
As discussed in Note 5, the Company incurred asset retirement obligations of $49,000 and $54,000 during the years ended March 31, 2011 and 2010, respectively, the value of which was determined using unobservable pricing inputs (or Level 3 inputs). The Company uses the income valuation technique to estimate the fair value of the obligation using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement.
Hedging Activities. We had no hedging activities in the years ended March 31, 2011 and 2010. 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. Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market. 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 to be used in future drilling operations or repair operations, is stated at the lower of cost or market, cost being determined by the FIFO method. See also Notes 2 and 3 below.
Commitments. The Company is committed to a total of $281,000 plus maintenance fees for a five-year lease term ending April 30, 2013 on a 4,000 square foot office space located in downtown Denver, Colorado. The Company does not have any off-balance sheet financing transactions, arrangements or obligations.
Major Customers and Operating Region. The Company operates exclusively within the United States of America. All of the Company's assets are employed in and all of its revenues are derived from the oil and gas industry. Individual external purchasers of 10% or more of the Company’s oil and gas production revenue for the years ended March 31, 2011 and 2010 were as follows:
For the years ended March 31, 2011 and 2010, approximately 48% and 57%, respectively, of Earthstone’s oil and gas revenue was from non-operated properties where the Company has no direct contact with the actual purchaser. On these properties, Earthstone’s portion of the product was marketed by the 23 different companies who operate these wells. These 23 companies may, unbeknownst to us, market to one or more of the same purchasers to whom we sell directly. 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 these purchasers, it has been estimated that the reduction in annual revenue would be less than 10%. It is not expected that the loss of any one of these purchasers would cause a material adverse impact on the Company’s results from operations, as alternative markets for oil and gas production are readily available.
Bad Debt Expense. A charge is recognized in general and administrative expenses and an allowance is established against specific receivable balances from joint interest owners in instances where working interest owners dispute amounts billed for their proportionate share in the cost of wells which the Company operates. As individual disputes are resolved, either the expense is reversed in the period of the resolution or the receivable is written down.
Share Based Compensation. The Company recognizes all equity based compensation as share based compensation expense, included in general and administrative expenses, based on the fair value of the compensation measured at the grant date. The expense is recognized over the vesting period of the grant. See Note 7 below for information.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions concern matters that are inherently uncertain. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from those estimates.
Reclassifications. Certain prior year amounts were reclassified to conform to current presentation. Such reclassifications had no effect on the prior year net income, accumulated deficit, net assets or total shareholders' equity.
Recent Accounting Pronouncements
In December 2008, the SEC decreed modified instructions for reporting oil and gas activities. The rule, effective and adopted for the Company’s year ended March 31, 2010, changes the oil and natural gas prices used to calculate reserve quantities and the full cost ceiling limitation from the spot price on the last day of the reporting period to the 12 month average prices, calculated as the unweighted arithmetic average price of oil and gas on the first day of each month for each of the 12 months prior to the last day of the reporting period (unless prices are defined by contractual arrangements). Adoption of this rule impacted depletion expense for the year ended March 31, 2010, as well as the ceiling test calculation for oil and gas properties as of March 31, 2010. Adoption of this rule for the year ended March 31, 2010 is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of this guidance, other than pricing, significantly impacted the financial statements, and it is impracticable to estimate the effect of applying the new rule on net income or the amount recorded for depletion for the year ended March 31, 2010.
In January 2010, the Financial Accounting Standards Board expanded the required disclosure of fair value measurements, requiring disclosure of the amounts and reasons for significant transfers between Level 1 and Level 2 of the fair value hierarchy, and disaggregation in the reconciliation for fair value measurements using significant unobservable inputs to separately provide information about purchases, sales, issuances and settlements. Effective for the Company’s year ended March 31, 2010, additional disclosure is also required about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring measurements. Adoption of this amendment, which solely amends disclosure requirements, results in no impact to the Company’s financial position, results of operations, or cash flows.
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.
Subsequent Events
For the period ended March 31, 2011, there were no subsequent events to recognize or disclose in the consolidated financial statements which would either impact the results reflected in this report or the Company’s results going forward.
2. Other Current Assets
Other current assets as of March 31, 2011 and 2010 consisted of the following:
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 for the years ended March 31, 2011 and 2010 consisted of the following:
Support equipment represents non-oil and gas property (including such items as vehicles, office furniture and equipment and well servicing equipment) and is stated at the lower of cost or market. Depreciation of support equipment was $34,000 and $36,000 for the years ended March 31, 2011 and 2010, respectively, which was computed using primarily the straight-line method over periods ranging from five to seven years.
Non-current 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, 2011 and 2010 consisted of the following:
5. Asset Retirement Obligation
For the purpose of determining the fair value of the asset retirement obligation incurred during the year ended March 31, 2011, the Company assumed an inflation rate of 4%, an estimated average asset life of 23.5 years, and a credit adjusted risk free interest rate of 8.4%.
The following reconciles the value of the asset retirement obligation for the periods presented. This included a short term obligation of $127,000 and $100,000 as of March 31, 2011 and 2010, respectively, which was a component of accrued liabilities on the balance sheet:
6. Commitments
Office rent expense was approximately $113,000 and $107,000 for the years ended March 31, 2011 and 2010, respectively (including building maintenance charges). The Company is committed to a total of $157,000 for the remaining term ending April 30, 2013.
The Company also has commitments pertaining to software, phone and copy machine maintenance contracts totaling $84,000, $80,000, and $13,000 for the years ending March 31, 2012, 2013, and 2014, respectively.
7. Shareholders’ Equity
Reverse Stock Split. Effective December 31, 2010, the Board of Directors authorized and effected a 1-for-10 reverse stock split which converted ten (10) shares of the Company’s common stock into one (1) share of common stock. The Board of Directors also authorized and effected a 1-for-5 reverse stock split for the number of authorized common shares and preferred shares as follows: (a) the reduction of the number of authorized shares of common shares from the then authorized 32,000,000 shares down to 6,400,000 shares, and (b) the reduction of the number of authorized shares of preferred shares from the then authorized 3,000,000 shares down to 600,000 shares. Both the common and preferred shares maintain a par value of $0.001. All references to the number of common shares, treasury shares, and per share amounts in the accompanying consolidated financial statements reflect the reverse stock split.
Preferred Shares. The Company has 600,000 shares of authorized preferred stock with a par value of $0.001 available for issuance in such series and preferences as determined by the Board of Directors. Since inception, the Company has not issued any preferred shares.
Common Shares. The Company has authorized 6,400,000 shares of common stock with a par value of $0.001. The total issued common stock as of March 31, 2011, was 1,782,000 common shares.
Share Based Compensation. On March 8, 2007, the Board of Directors adopted a Director Compensation Plan (“the Plan”) allotting up to 50,728 shares of the Company’s common stock to be issued to independent, non-employee directors. In connection with the 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. Shares are subject to certain restrictions and vesting.
During the year ended March 31, 2011, 9,270 shares of common stock reserved for issuance under the Plan were authorized for issuance. Accordingly, as of March 31, 2011, 20,716 shares of common stock remain available for issuance under the Plan. Grants of shares of restricted stock vest one-third each year over three years. 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 March 31, 2011, for each non-employee director was as follows: Robertson - 8,555 shares; Rodgers - 8,555; and Calerich - 552. In addition, each of the three independent directors was granted 1,867 shares of restricted stock on April 1, 2011, subject to vesting and forfeiture. All restricted shares are considered issued and outstanding shares of the Company’s common stock at the grant date and have the same dividend and voting rights as other common stock.
On January 4, 2011, the Board of Directors authorized the Company to increase the Board of Directors to four members in accordance with the Bylaws. On January 6, 2011, Andrew P. Calerich was appointed a seat on the Board of Directors and was granted restricted common stock valued at $9,000, subject to a vesting period similar to other directors, ergo the aforementioned 552 restricted shares. Consistent with the calculation of shares for the annual grant of stock to directors, the number of restricted shares was determined by the average closing share price for the last ten trading days of the quarter ended December 31, 2010. This price, adjusted for the reverse stock split, was $16.30.
A summary of the status of the Company’s nonvested shares under the Director Compensation Plan as of March 31, 2011 and 2010, and changes during the years ended on those dates is presented below:
As of March 31, 2011, there was $80,000 of total unrecognized compensation cost related to nonvested share based compensation arrangements granted under the Director Compensation Plan. That cost is expected to be recognized over a weighted-average period of 1.02 years.
The Company granted one key employee 624 restricted shares of Company common stock during the year ended March 31, 2010, valued at $5,000. Such shares vest one-third each year over three years, subject to forfeiture.
Share based compensation expense of $75,000 and $72,000 was recognized during the years ended March 31, 2011 and 2010, respectively, for restricted share grants to independent directors.
Treasury Shares. On October 22, 2008, the Company’s Board of Directors authorized a share buyback program for the Company to repurchase up to 50,000 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 150,000. 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, 2011, 10,997 shares were repurchased under the share buyback program and 109,440 shares remain available for future repurchase. No treasury shares have been retired.
8. Income Taxes
The provision for income taxes for the years ended March 31, 2011 and 2010 is 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, 2011 and 2010 follows:
The overall effective tax rate expressed as a percentage of book income before income taxes for year ended March 31, 2011, as compared to the ended March 31, 2010, was lower due to the Company having an increase in deferred tax assets from the amounts originally estimated on the prior year tax provision.
Net income tax payments were $204,000 and $7,000 for the years ended March 31, 2011 and 2010, respectively.
Net deferred tax assets and liabilities for the years ended March 31, 2011 and 2010 were comprised of:
Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, deferred tax assets and liabilities are continually re-evaluated and numerous estimates are revised over time. As such, deferred taxes may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves and the depletion of these long-lived reserves.
The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions. The tax years remaining subject to examination by tax authorities are the years ended March 31, 2007 through 2010.
9. Related Party Transactions
The Company maintains a policy permitting officers or directors to assign to the Company or receive assignments from the Company in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. This policy also allows officers or directors and the Company to 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, Earthstone’s President and Chief Executive Officer, 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 the years ended March 31, 2011 and 2010, no other director or officer participated with the Company in any oil and gas transaction. In prior years, Mr. Singleton has participated with the Company in the acquisition of producing properties on the same terms and conditions as 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, as of March 31, 2011, the Company had an accrued balance due from Mr. Singleton of $11,000 for his share of operating expenses on these wells, which was billed ten days after year end and for which timely payment was subsequently received. As of March 31, 2010, as a result of his share of oil and gas revenue exceeding the amount of his share of operating expenses, the Company had a balance of $10,000 due to Mr. Singleton.
10. Oil and Gas Property
The aggregate amount of capitalized costs related to oil and gas property and the aggregate amount of related accumulated depletion as of March 31, 2011 and 2010 are as follows:
The following shows, by category and year incurred, the oil and gas property costs applicable to unproved property that were excluded from the full cost pool depletion computation as of March 31, 2011:
Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2011 and 2010 are summarized as follows:
11. Unaudited Oil and Gas Reserves Information
As of March 31, 2011 and 2010, 91% and 93%, 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 9% and 7% of the reserve estimates, respectively, were prepared internally by the Company’s management.
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 - Estimates reflect steady increases in oil and gas prices since December 2008, when prices reached a 5-year low. Changes in performance constitute less than 10% of the total amount of revisions of previous estimates.
²
Extensions and Discoveries - Eleven wells represent extensions and discoveries during the year ended March 31, 2011, in North Dakota (7), Montana (2), Colorado (1) and Texas (1). Additions during the year ended March 31, 2010, consisted of 2 new wells in Colorado and 1 new well in North Dakota. Additions during the year ended March 31, 2009, pertained to the 16 wells drilled in Colorado.
³
Production - Volumes of oil and gas that were produced were removed from reserves during the year.
The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s 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 as of March 31, 2011 and 2010. Estimated future cash flows for the year ended March 31, 2009 were based on the spot price on the last day of the reporting period. This change is a result of the modified instructions from the SEC for reporting oil and gas activities, as explained in Note 1 above, effective and adopted for the Company’s year ended March 31, 2010. 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 each of the years ended March 31, 2011, 2010, and 2009:
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 Interim Chief Financial 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, 2011. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Interim Chief Financial Officer concluded that, as of March 31, 2011, 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 Interim Chief Financial 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, 2011.
Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to 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 2011 annual shareholders’ 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 2011 annual shareholders’ meeting and is incorporated by reference in this report.
ITEM 12
ITEM 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2011 annual shareholders’ 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 2011 annual shareholders’ 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 2011 annual shareholders’ 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 shareholders of the Company at the Company’s 2009 Annual Meeting of Shareholders 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(i)c
Certificate of Amendment to Certificate of Incorporation dated December 20, 2010 are incorporated by reference to Exhibit 3(i) on Form 8-K filed with the SEC on January 4, 2011.
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 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, shareholder 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 shareholders’ 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.
4.2
Specimen Stock Certificate of Earthstone Energy, Inc., filed herewith.
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 year ended March 31, 1985, filed with the SEC.
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, incorporated by reference to Exhibit 10.4 of our Annual Report on Form 10-K for the year ended March 31, 2010, filed with the SEC on June 18, 2010.
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 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.
10.7*
Financial Consulting Agreement, effective March 16, 2011, between QAS, LLC and Earthstone, filed herewith.
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 year ended March 31, 2004, filed with the SEC on May 11, 2005.
Subsidiary List, 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, President and Chief Executive Officer).
31.2
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial 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, President and 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 (Jim Poage, Interim Chief Financial 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 15, 2011
Ray Singleton, President and Chief Executive Officer
By: /s/ Jim Poage
June 15, 2011
Jim Poage, Interim Chief Financial 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 15, 2011
Ray Singleton, Director
By: /s/ Richard K. Rodgers
June 15, 2011
Richard K. Rodgers, Director and
Compensation Committee Chairman
By: /s/ Monroe W. Robertson
June 15, 2011
Monroe W. Robertson, Director and
Audit Committee Chairman
By: /s/ Andrew P. Calerich
June 15, 2011
Andrew P. Calerich, Director