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EXCEL - IDEA: XBRL DOCUMENT - EARTHSTONE ENERGY INCFinancial_Report.xls
EX-32.2 - CERTIFICATION - EARTHSTONE ENERGY INCeste_ex322.htm
EX-32.1 - CERTIFICATION - EARTHSTONE ENERGY INCeste_ex321.htm
EX-31.2 - CERTIFICATION - EARTHSTONE ENERGY INCeste_ex312.htm
EX-31.1 - CERTIFICATION - EARTHSTONE ENERGY INCeste_ex311.htm
EX-23.1 - CONSENT - EARTHSTONE ENERGY INCeste_231.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

þ
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Fiscal Year Ended March 31, 2014
 
o
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission file number: 001-35049
 
 
(Exact Name of Registrant as Specified in its Charter)

Delaware
 
84-0592823
(State of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
     
633 17th Street, Suite 2320 Denver, Colorado
 
80202-3619
(Address of principal executive office)
 
(Zip Code)
 
(303) 296-3076
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
Name of each exchange on which registered
Common Stock, $0.001 par value per share
NYSE MKT LLC
 
Securities registered under Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No þ

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer o
 
Accelerated filer o
 
Non-accelerated filer o
(Do not check if a smaller reporting company)
 
Smaller reporting company þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Registrant’s revenues for its most recent fiscal year: $17,514,000

The aggregate market value of registrant’s common stock held by non-affiliates was approximately $21,048,567 as of the registrant’s most recently completed second fiscal quarter.

As of June 9, 2014, 1,729,123 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from portions of the registrant's definitive Proxy Statement for its 2014 Annual Meeting of Shareholders to be filed, pursuant to Regulation 14A, no later than 120 days after March 31, 2014.


 
 
 
 
 
FORWARD-LOOKING STATEMENTS

This Current Report on Form 10-K, including information incorporated herein by reference, contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "predict," "plan," "should," "likely," "may," "will," "continue" or similar expressions are intended to identify such statements. All statements other than statements of historical facts that address activities that we intend, expect or anticipate will or may occur in the future are forward-looking statements. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty. Forward-looking statements relate to, among other things:

   our strategies, either existing or anticipated;
   our future financial position, including anticipated liquidity; 
   our ability to satisfy obligations from cash generated from operations;
   amounts and nature of future capital expenditures, including future share repurchases;
   acquisitions and other business opportunities;
   operating costs and other expenses, including asset retirement obligation expenses;
   wells expected to be drilled, other anticipated exploration efforts and associated expenses;
   estimates of proved oil and natural gas reserves, deferred tax assets, and depletion rates;
   our ability to meet additional acreage, seismic and/or drilling cost requirements; and
   other estimates and assumptions we use in our accounting policies.
 
Factors that could cause actual results to differ materially from our expectations include, among others, such things as:

   loss of senior management or technical personnel;
   oil and natural gas prices and production costs;
   our ability to replace oil and natural gas reserves, including changes in reserve estimates resulting from expected oil and gas prices, production rates, tax rates and production costs;
   our ability to remain in compliance with the financial covenants related to our Credit Facility may be affected by events beyond our control, including market prices for our oil and gas. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect our liquidity by rendering us unable to borrow further under the Credit Facility;
   exploitation, development, production and exploration results, including mechanical failure;
   the estimated costs of asset retirement obligation, including whether or not those retirement costs, in whole or in part, are ever actually incurred in the future;
   the potential unavailability of drilling rigs and other field equipment and services;
   the existence of unanticipated liabilities relating to existing properties or those acquired in the future, including environmental liabilities;
  factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment;
   the willingness and ability of third parties to honor their contractual commitments;
   permitting issues;
   the nature, extent and duration of workovers;
   the impact and costs related to compliance with or changes in laws governing our operations;
   acquisitions and other business opportunities (or the lack thereof) that may be pursued by us;
   competition for properties and the effect of such competition on the price of those properties;
   economic, market or business conditions, including any change in interest rates or inflation;
   the lack of available capital and financing;
   risk factors consistent with comparable companies within our industry, especially companies with similar market capitalization and/or employee census; and
   weather or other factors, many of which are beyond our control.

Furthermore, forward-looking statements are made based on our current assessment available at the time. Subsequently obtained information concerning the merits of any property, as well as changes in estimated exploration and development costs and ownership interest, may result in revisions to our expectations and intentions and, thus, we may alter our plans regarding any exploration and development activities.

Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations may prove to be incorrect. As with comparable companies within our industry, there are numerous factors that could cause actual results to differ materially from our expectations. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.
 
 
 
2

 
 
 
GLOSSARY OF TERMS

Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report:

Terms used to describe quantities of crude oil and natural gas:

Bbl” – Barrel or 42 U.S. gallons liquid volume.

BOE” – Barrels of crude oil equivalent.

Condensate” – A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
 
Mcf” – Thousand cubic feet of gas.

Terms used to describe our interests in wells and acreage:

Gross acres” – The number of acres in which we own a gross working interest.

Gross well” – A well in which we own a working interest.

Net acres” – Our percentage ownership of gross acreage. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

Net well” – Deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

Developed acreage” – Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Development well” – A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves.

Disposal well” – A well used for the disposal of water resulting from the production of oil and gas. Oil and gas reservoirs are usually found in porous rocks, which also contain saltwater. This saltwater, which accompanies the oil and gas to the surface, is disposed over time through injection into underground porous rock formations not productive of oil or gas.

Dry hole” – An exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.

Exploratory well” – A well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir.

Injector well” – A well used for the injection of water, gas, steam or CO2 into an oil or gas producing reservoir/unit in order to maintain reservoir pressure, heat the oil or lower its viscosity, in order to increase oil and/or gas recovery and to safely dispose of the salt and/or fresh water produced with oil and natural gas.

Productive well” – An exploratory or a development well that is not a dry hole.
 
 
 
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Undeveloped acreage” – Leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil and natural gas, regardless of whether or not such acreage contains proved reserves. Undeveloped acreage includes net acres under the bit until a productive well is established in the spacing unit.

Unproved property” – A property or part of a property with no proved reserves.

Unsuccessful efforts” – Drilling activities that result in a dry hole. Costs associated with unsuccessful efforts are part of the cost to discover reserves, therefore are capitalized in the full cost pool.

Terms used to describe seismic activity and operations:

Fracturing” – The injection of water, sand and additives under hydraulic pressure into prospective rock formations at depth to stimulate oil and natural gas production.
 
Horizontal drilling” – A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontal within a designated zone typically defined as the prospective pay zone to be completed for oil and/or gas.

Hydraulic stimulation technology” – A synonym for “fracturing.” A process that results in the creation of fractures in rocks. The fracturing is done from a wellbore drilled into reservoir rock formations at depth to increase the rate and ultimate recovery of oil and natural gas.

Plugging and abandonment” – The sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Recompletion” – The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
 
Workover – Operations on a producing well to restore or increase production.

Terms used to describe the legal ownership of our oil and natural gas properties:

Revenue interest” – The amount or percentage of revenue/proceeds derived from a producing well that the owner is entitled to receive.

Working interest” – The amount or percentage of costs that an owner is required to pay of drilling and production expenses. It also gives the owners, in the aggregate, the right to drill, produce and conduct operating activities on the property.

Terms used to assign a present value to or to classify our reserves:

 “PV-10 – The estimated future cash flow, discounted at a rate of 10% per annum, with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the U.S. Securities and Exchange Commission (“SEC”).

 “Proved developed non-producing reserves” – Proved crude oil and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

Proved developed reserves” – Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
 

 
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Proved reserves” – Proved crude oil and natural gas reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves – Proved crude oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same reservoir.
 
Standardized measure” – The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

Other Terms:

Farmout” – An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farmin" while the interest transferred by the assignor is a "farmout."

Field” – An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Play” – An accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area expanse.

Prospect” – A location where hydrocarbons such as oil and gas are believed to be present in quantities which are economically feasible to produce.

Reservoir” – A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Resources” – Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
 
 
 
 
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Earthstone Energy, Inc.
Form 10-K
March 31, 2014
Table of Contents

     
Page
 
Part I
Item 1.
Description of Business
   
7
 
Item 1A.
Risk Factors
   
13
 
Item 1B.
Unresolved Staff Comments
   
13
 
Item 2.
Description of Property
   
13
 
Item 3.
Legal Proceedings
   
17
 
Item 4.
Mine Safety Disclosures
   
17
 
           
Part II
Item 5.
M    Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
   
18
 
Item 6.
Selected Financial Data
   
20
 
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
   
20
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
   
26
 
Item 8.
Financial Statements and Supplementary Data
   
26
 
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
   
47
 
Item 9A.
Controls and Procedures
   
47
 
Item 9B.
Other Information
   
48
 
           
Part III
Item 10.
Directors, Executive Officers and Corporate Governance
   
49
 
Item 11.
Executive Compensation
   
49
 
Item 12.
Se   Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
   
49
 
Item 13.
Certain Relationships and Related Transactions and Director Independence
   
49
 
Item 14.
Principal Accountant Fees and Services
   
49
 
           
Part IV
Item 15.
Exhibits, Financial Statement Schedules
   
50
 
 
Signatures
   
52
 

 
 
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Part I
 
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 to Earthstone Energy, Inc. in 2010. 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 and South Texas. As of March 31, 2014, our estimated net proved oil and natural gas reserves were 2,554,000 Bbls of oil and condensate and 3,413,000 Mcf of natural gas.

Recent Developments – Pending Strategic Combination

On May 15, 2014, the Company announced that it had entered into an Exchange Agreement (the “Exchange Agreement”) with Oak Valley Resources, LLC (“Oak Valley”) whereby the membership interests in three subsidiaries of Oak Valley, inclusive of producing assets, undeveloped acreage and an estimated $138 million of cash, would be contributed and transferred to the Company in exchange for the issuance of approximately 9.1 million shares of the Company’s common stock (“Common Stock”) to Oak Valley (the “Exchange”). Following the Exchange, current Company stockholders will own 16% of the Company's outstanding Common Stock and Oak Valley will own 84% of the Company's outstanding Common Stock.  Closing conditions include, approval by our shareholders for the issuance to Oak Valley of the Common Stock in the Exchange, approval by our shareholders of an amendment to the certificate of incorporation to increase our authorized capital to 100,000,000 shares of Common Stock and 20,000,000 shares of preferred stock and listing approval by NYSE MKT of the Common Stock to be issued to Oak Valley in the Exchange. It is anticipated that the Exchange will not be completed until the third calendar quarter of 2014, subject to customary and specific closing conditions. There are no assurances that all of the closing conditions to the Exchange will be satisfied, or that the Exchange will be consummated.

Pending closing of the Exchange, the Company has agreed in the Exchange Agreement to various covenants and restrictions related to the conduct of its business including, among others, (i) to conduct its business in the ordinary course consistent with past practices, (ii) to retain the services of its present officers and key employees, (iii) to use commercially reasonable efforts to comply in all material respects with applicable laws and material contracts, (iv) not to issue, sell, grant, dispose of, accelerate or modify, as appropriate, any of its securities, (v) not to redeem, purchase or acquire any of its outstanding securities, except in connection with the vesting, settlement or forfeiture of, or tax withholding with respect to, any equity or equity-based awards granted under any Company equity plan that is outstanding as of date of the Exchange Agreement, (vi) not to incur, refinance or assume any indebtedness for borrowed money other than borrowings under the Company’s existing credit facility, (viii) not to sell, transfer, lease, farmout or otherwise dispose of any of the Company’s properties with a fair market value in excess of $1 million, (ix) not to make any unbudgeted capital expenditure(s) in excess of $5 million, without consultation and consent of Oak Valley, which consent shall not be unreasonably withheld, delayed or conditioned, or except as may be reasonably required to conduct emergency operations, repairs or replacements on any well, pipeline or other facility, or (x) not to (A) materially increase the compensation of any executive officer, (B) pay any bonus or incentive compensation, (C) grant any new equity or non-equity based compensation award, except as required by applicable law or any employee benefit plans. The Company does not anticipate that the subject covenants and restrictions agreed to in the Exchange Agreement will materially interfere with, change, alter or otherwise impact, the Company’s on-going and continuing activities over the next several months until the Exchange is consummated or otherwise terminated.

The foregoing descriptions of the Exchange and the Exchange Agreement do not purport to be complete and are qualified in their entirety by the terms and provisions of the Exchange Agreement, a copy of which is attached to the Current Report on Form 8-K as filed by the Company with the U.S. Securities Exchange Commission on May 16, 2014. A copy of the subject Form 8-K can be obtained by accessing the SEC’s website at http://www.sec.gov.



 
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Strategy
 
Our primary objective is to enhance shareholder value 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 strategy set forth below is based on Earthstone as it is now configured. If the Exchange is completed, the management and properties of Earthstone will change, as will the strategic direction and property development priorities.
 
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 in 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.

Last year, Earthstone began a re-evaluation of the West Cole Unit and the West Cole North Unit (Units); our long-held, waterflood properties in Webb County, Texas.  As a result, the Company identified 11 potential new locations that could prove productive.  The Company has begun to evaluate three of these locations.  If these three wells prove to be economic producers, the Company has eight remaining locations that could be drilled.

In addition to the Williston Basin and South Texas, we are pursuing an exploration project in the Nebraska portion of the Denver-Julesburg (DJ) Basin. While the Nebraska panhandle has long been a producing region with a high density of shallow wells, it has only been sparsely explored in its deeper horizons. Based on 3D seismic, the Company had identified eight areas of interest, or prospects within the area.  After drilling a dry hole last year on one our prospects, Earthstone is re-evaluating our seismic interpretation, our remaining prospects and other areas within Cheyenne County, Nebraska that may be of interest.  Earthstone is, and will be, the operator of wells drilled in this project.

Last year, non-operated drilling projects comprised the majority of capital expenditures. In the coming year, we expect this trend to continue despite our Nebraska project, due to the size of the Bakken exposure we now have in North Dakota. We expect to continue to emphasize the acquisition of producing properties. However, these efforts are typically not predictable and are opportunistic in nature.
 
Historically, we have not placed emphasis on acquiring new, large, non-producing acreage positions. In the coming year, as our existing inventory of North Dakota acreage is developed, we may shift capital expenditure dollars into undeveloped acreage in this area.

We will be focusing on keeping our operating costs under control. However, we expect rig and vendor service costs to continue to escalate, especially in North Dakota and Montana, due to high demand. Maintaining a low overhead structure is fundamental to our cost containment. However, over the last two years we have expanded and/or restructured our staff to increase our operational capability in preparation for our Nebraska project, to more closely monitor and maintain our Bakken acreage and to comply with increased regulation. 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 our current expectations have, and may in the future, be altered by subsequent events, including the Exchange, or other, more attractive opportunities that may present themselves in the future.
 
 
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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 this calendar year. These areas are the Banks and Indian Hill Fields in McKenzie County, North Dakota. While this is not our primary area of focus, we continue to deploy capital in areas beyond the Williston Basin to exploit reserve potential both on existing properties and new prospects.

Banks Field — McKenzie County, North Dakota. In the last year, 32 horizontal Bakken/Three Forks wells in which we had interests were completed and brought onto production.  All of these wells are being operated by Statoil. Drilling commenced on an additional seven wells in which we have interests, but as of March 31, 2014, these wells have not been completed. All seven wells are considered to be Proved Undeveloped, per SEC criteria.  Based on information available at this time, we are anticipating an additional 99 wells in this prospect.

Indian Hill & Camel Butte Fields — McKenzie County, North Dakota.  We currently have an interest in two horizontal Bakken/Three Forks wells in the Indian Hill Field and three horizontal Bakken/Three Forks wells in the Camel Butte Field.  We, along with Continental Resources, Inc., have commenced drilling five horizontal Bakken/Three Forks wells, but as of March 31, 2014, these wells have not been completed.  Conoco Phillips drilled and completed one well in the Camel Butte Field.  These five Continental wells are considered to be Proved Undeveloped, per SEC criteria.

Elm Coulee Field — Richland County, Montana. We currently have 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.
.
Bailey, Champion & Murphy Creek Fields — Dunn County, North Dakota. We currently have an interest in nine producing horizontal Bakken wells.

Mondak Field — McKenzie County, North Dakota. We currently have an interest in three horizontal Bakken wells in the Mondak Field. This acreage is currently developed for one well per spacing unit. However, we anticipate that this acreage will be developed at higher densities in the future.
 
 
 
 
9

 

Divide County, North Dakota — Sheridan County, Montana. In both of these counties we hold undeveloped acreage by virtue of existing vertical wells.  The acreage is probable for Bakken or Three Forks development.  In the past year, several companies have drilled horizontal Bakken or Three Forks wells in the area, albeit with limited success.  In 2012, we acquired three producing vertical wells, along with each wells’ associated acreage.  We also participated with Vess Oil Corporation in the drilling of a horizontal Ratcliffe well in the Rush Mountain Field of Sheridan County with a 10% working interest.  Given cost overruns by Vess, the well was less than successful.  Vess has the right to propose additional horizontal Ratcliffe wells, but so far has declined to do so.

Permo-Penn Play, Nebraska, DJ Basin. We acquired approximately 70 square miles of 3D seismic data and 30,000 gross acres of leasehold primarily in Cheyenne County.   The deeper formations in this area are relatively unexplored; in some cases less than one deep well per township. However, by Williston Basin standards, these wells are much shallower and are inexpensive to drill. Our initial effort was a vertical well that resulted in a dry hole.  Going forward, as we gain better knowledge of the deposits, we may incorporate horizontal drilling into our exploration efforts. We are the Operator of this venture and have a 45% working interest.

Reserves

During the year ended March 31, 2014, our proved reserves in BOE and PV-10 increased approximately 7% and 43%, respectively (from March 31, 2013). Additional information about our reserves and the calculation of reserves may be referenced in Item 2. “Description of Property.”

Contemplated Activities

We are continually evaluating other drilling and acquisition opportunities for possible participation. 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.
 
 
 
 
10

 

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, 2014, approximately 20% of our oil and natural gas production revenues were received from sales to seven purchasers (compared to 35% to six purchasers in the previous fiscal year). The remaining 80% 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 25 different companies who operate these wells. These 25 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.

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, as a small company with limited market liquidity, we compete with larger companies that have greater, more efficient, access to the capital markets.  Finally, as “resource plays” have evolved, the industry has become much more capital intensive and our exposure to opportunities has been diminished due to our limited resources.

Employees

As of March 31, 2014, we had 12 full-time, three part-time employees and four part-time contractors. Five of these employees are primarily field laborers and are located at our subsidiary’s (Basic Petroleum Services, Inc.) field office in Bruni, Texas, 45 miles southeast of Laredo, Texas. In addition, in other areas, we have five 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.
 

 
11

 
 
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.

The Company engages in hydraulic fracturing activities. Each state has comprehensive laws and regulations to provide for safe well construction practices and operations to ensure the protection of drinking water sources. To our knowledge, the Company is, and remains, in compliance with all federal, state and local provisions which have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. With regards to the magnitude of our use of hydraulic fracturing of oil and gas wells, the Company holds a minority interest in a number of wells that are under the management and control of far larger companies who apply various stimulation strategies. The Company’s ownership varies on these new drilling projects from 0.1% to 6.5% interest depending on the specific well. With these small interests, if a containment failure were to occur on a single well, it is not likely that the event would have a material financial or operational impact on the Company.

Potential environmental effects may also arise from the use of disposal and injector wells. We hold a working interest in five disposal and seven injector wells, nine of which we operate, the remaining of which are owned and operated by third parties whose disposal practices are outside of our control.

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 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.”
 
 
 
12

 
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. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. DESCRIPTION OF PROPERTY

Producing Properties: Location and Impact

As of March 31, 2014, we owned a working interest in 157 gross producing oil wells, three gross producing gas wells, six disposal wells and seven injector wells.

Productive Wells

   
Gross Wells
   
Net Wells
 
   
Oil
   
Gas
   
Oil
   
Gas
 
                                 
North Dakota
   
99
     
2
     
10.77
     
0.13
 
Montana
   
28
     
     
11.98
     
 
Texas
   
27
     
     
24.10
     
 
Louisiana
   
2
     
     
0.11
     
 
Colorado
   
     
1
     
     
0.05
 
Wyoming
   
1
     
     
0.47
     
 
Total
   
157
     
3
     
47.43
     
0.18
 

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, 2014, our estimated proved oil and natural gas reserves in barrels of oil equivalent (“BOE”) was 3,123,000, a 7% increase from the prior year end’s estimated proved oil and natural gas reserves of 2,921,000 BOE. This increase primarily reflects the addition of new wells.

 Geographically, our reported reserves are located in two primary areas: the Williston Basin in North Dakota and Montana and Onshore South Texas. The following table summarizes the estimated proved developed oil and natural gas reserves for these two areas as of March 31, 2014.  While we hold interests in producing wells outside of these two primary locations, these wells are not reported in the following table due to their insignificance.
 
 
13

 
 
Estimated Proved Developed Oil and Gas Reserves by Area
 
 
Net Oil
 
Net Gas
         
 
(Bbls)
 
(Mcf)
 
BOE
 
%
 
                 
Williston Basin
   
1,093,000
     
1,773,000
     
1,389,000
     
76.2
%
                                 
South Texas/Onshore Gulf Coast
   
433,000
     
     
433,000
     
23.8
%
                                 
Total
   
1,526,000
     
1,773,000
     
1,822,000
     
100.0
%

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. All of our reported oil and natural gas reserves have been estimated as of March 31, 2014 and 2013, by the Ryder Scott Company (“Ryder Scott”) of Houston, Texas. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 75 years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. Ryder Scott has over 80 engineers and geoscientists on their permanent staff. The office of Ryder Scott that prepared our reserves estimates is registered in the state of Texas (License #F-1580). Ryder Scott prepared our reserve estimate 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 9, 2014, 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.
  
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 and pressure data available through March 31, 2014. The data used in this analysis was obtained from public data sources and was considered sufficient for calculating producing reserves. The proved undeveloped reserves were estimated by the analogy method. The analogy method uses pertinent well data obtained from public data sources that were available through March 31, 2014.

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 the Financial Accounting Standards Board (“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.
 
 
14

 

The following table sets forth certain information regarding estimates of our oil and gas reserves as of March 31, 2014. All of our reserves are located in the United States.
 
Estimated Proved Developed and Undeveloped Oil and Gas Reserves

   
Proved Developed
             
   
Producing
   
Non-Producing
   
Proved Undeveloped
   
Total Proved
 
                         
Net Remaining Reserves
                       
Oil/Condensate - Bbls
   
1,526,000
     
     
1,028,000
     
2,554,000
 
Plant Products - Bbls
   
     
     
     
 
Gas – Mcf
   
1,773,000
     
     
1,640,000
     
3,413,000
 

Estimated Proved Undeveloped Oil and Gas Reserves

During 2014, we had a positive revision of 14,000 BOE, or 1%, of our March 31, 2013 estimated proved undeveloped reserves balance.  The primary cause for these revisions was due to increases in pricing which extended the economic life of the wells.  Within portions of our areas of operation, actual well results underperformed relative to the proved undeveloped forecasts in our March 31, 2013 reserve report.  The proved undeveloped forecasts in these areas have been adjusted to reflect these well performances in our March 31, 2014 reserve report.  A reconciliation of the change in proved undeveloped reserves during the year ended March 31, 2014 is as follows:

     
 
BOE
 
     
Estimated Proved Undeveloped Reserves, beginning of year
    1,336,000  
PUD converted to PDP
    (506,000
PUD added during the year
    457,000  
Revisions of previous estimates
    14,000  
Estimated Proved Undeveloped Reserves, end of year
    1,301,000  

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.
 
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” wherein we present our net oil and gas production, the average sales price, and the average cost of production per BOE, for the years ended March 31, 2014 and 2013.
 
 
15

 

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, 2014, 2013 and 2012, respectively:

Exploratory and Developmental Wells Drilled

   
2014
   
2013
   
2012
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Exploratory
                                   
   Productive
                                   
    Oil
   
     
     
     
     
     
 
    Gas
   
     
     
     
     
     
 
   Dry holes
   
1
     
0.45
     
     
     
     
 
                                                 
Total Exploratory
   
1
     
0.45
     
     
     
     
 
                                                 
Developmental
                                               
   Productive
                                               
    Oil
   
35
     
1.45
     
20
     
0.508
     
18
     
0.74
 
    Gas
   
     
     
     
     
     
 
   Dry holes
   
     
     
     
     
     
 
                                                 
Total Developmental
   
35
     
1.45
     
20
     
0.508
     
18
     
0.74
 
                                                 
Total Exploratory and Developmental Wells Drilled
   
36
     
1.9
     
20
     
0.508
     
18
     
0.74
 

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

   
Developed Acreage
   
Undeveloped Acreage
 
   
Gross
   
Net
   
Gross
   
Net
 
                                 
Louisiana
   
     687
     
      51
     
 —
     
 —
 
Montana
   
7,053
     
2,090
     
12,472
     
2,557
 
Nebraska
   
     
     
30,469
     
11,700
 
North Dakota
   
25,315
     
2,572
     
5,809
     
1,614
 
Texas
   
2,807
     
2,464
     
 —
     
 —
 
Utah
   
    —
     
     
42,736
     
       441
 
Wyoming
   
1,118
     
149
     
      5,701
     
781
 
                                 
Total
   
36,980
     
7,326
     
97,187
     
17,093
 
 
Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of oil and natural gas.
 
 
16

 
 
Leasehold Acreage Expirations
 
A significant portion of our acreage is not currently held by production or held by operations.  Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire.  If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related properties.  Drilling plans for these areas are generally in the discretion of third party operators and are subject to change based on various factors that are beyond our control, such as the availability and cost of capital, equipment, services and personnel; seasonal conditions; regulatory and third party approvals; oil, natural gas liquids (“NGL”) and natural gas prices; results of title work; gathering system and other transportation constraints; drilling costs and results; and production costs.  As of March 31, 2014, we estimate that we had leases that were not developed that represented 12,204 net acres potentially expiring as follows:

Future Expirations of Net Acreage

   
March 31,
 
   
(in net acres)
 
Future expirations of net acreage:
       
2015
   
656
 
2016
   
1,715
 
2017
   
1,423
 
2018
   
5,960
 
2019
   
2,206
 
   Thereafter
   
244
 
         
     
12,204
 
 
Office Lease

We currently lease approximately 7,000 square feet of office space in downtown Denver, Colorado from an independent third party for approximately $9,880 per month plus maintenance fees. The lease term ends on April 30, 2016. For additional information see Note 7 to the consolidated financial statements.
 
ITEM 3. LEGAL PROCEEDINGS

None.
 
ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.
 
 
17

 

Part II
 
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

Our common stock is currently quoted on NYSE MKT under the ticker symbol “ESTE”.

The closing bid price on NYSE MKT of our common stock on June 9, 2014, was $29.20.

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 NYSE MKT. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

   
Year Ended March 31,
 
   
2014
 
2013
 
   
High
   
Low
 
High
 
Low
 
                         
First Quarter
 
$
16.49
   
$
13.26
   
$
22.75
   
$
15.54
 
Second Quarter
   
17.20
     
12.70
     
16.25
     
13.44
 
Third Quarter
   
19.21
     
16.06
     
18.11
     
14.74
 
Fourth Quarter
   
22.70
     
17.48
     
18.50
     
15.74
 


As of June 9, 2014, we had approximately 1,869 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 and will be dependent upon the Company’s earnings and financial condition, receipt of our lender’s consent and other factors. Our Board presently has no plans to pay any dividends in the foreseeable future.



 
18

 

Unregistered Sales of Equity Securities

Not applicable.

Purchases of Equity Securities
 
The following summarizes monthly share repurchase activity for the fourth quarter of the year ended March 31, 2014:

   
Total Number of Shares Purchased
   
Average Price Paid Per Share
   
Number of Shares Purchased as Part of a Publicly Announced Plan
   
Maximum Shares that May Yet be Purchased under the Plan
 
January 1, 2014 - January 31, 2014
   
   
$
     
     
103,254
 
February 1, 2014 - February 28, 2014
   
   
$
     
     
103,254
 
March 1, 2014 - March 31, 2014
   
   
$
     
     
103,254
 
                                 
Total
   
             
         

 
 
19

 

ITEM 6. SELECTED FINANCIAL DATA

As a “smaller reporting company,” we are not required to provide this information.

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.
 
The discussion set forth describes Earthstone as it is currently configured. If the Exchange agreement is completed, our liquidity outlook, capital structure and planned capital expenditures will be significantly different.
 
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 and available line of credit, should enable us to meet our existing and normal recurring obligations during the next year and beyond.

On December 21, 2012, we entered into a $25 million senior secured revolving bank Credit Facility with the Bank of Oklahoma (“Bank”) which provides an additional source of funds to pay our share of drilling and completion costs incurred on wells drilled and completed primarily in the Williston Basin, but also elsewhere. The initial borrowing base on the Credit Facility was $6 million.  Among other provisions, the Credit Facility contains certain affirmative and negative covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios.  For further information concerning the Credit Facility and its terms, see our Form 8-K filed with the SEC on January 3, 2013.

Effective September 10, 2013, we entered into a Waiver and First Amendment to Credit Agreement (the “Amended Credit Facility”) with the Bank in connection with a semiannual redetermination of the borrowing base.  The redetermination resulted in an increase in the borrowing base from $6 million under the initial Credit Facility to $12 million under the Amended Credit Facility, which amount is subject to redetermination.  As of March 31, 2014, we had an outstanding balance due of $9 million under the Amended Credit Facility and were in compliance with all covenants contained in the Amended Credit Facility. Our ability to remain in compliance with the financial covenants may be affected by events and other factors beyond our control, including market prices for our oil and gas and the rate at which the operators of projects in which we participate drill. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect our liquidity by rendering us unable to borrow further under the Amended Credit Facility.  For further information concerning the Amended Credit Facility and its terms, see the Exhibits below in Part IV – Item 15 of this Form 10-K.

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.


 
20

 
 
Hedging. During the years ended March 31, 2014 and 2013, we did not participate in any hedging activities, nor did we have any open futures or option contracts.

Working Capital. As of March 31, 2014, we had a working capital surplus of $2,694,000 (a current ratio of 1.47:1) compared to a working capital surplus as of March 31, 2013 of $775,000 (a current ratio of 1.14:1). The increase in current ratio is primarily a result of an increase in oil and gas sales that remained collectible at March 31, 2014 when compared to the prior year, due to an increase in oil and gas sales between the two years.

Cash Flow. Cash provided by operating activities increased from $3,867,000 for the year ended March 31, 2013 to $6,441,000 for the year ended March 31, 2014.  Changes in operating cash relate primarily to the increase in net income adjusted for non-cash expenses for the year ended March 31, 2014 compared to the comparable prior period. Deferred income tax expense and depletion primarily related to the increase in the oil and gas property balances, coupled with the  timing and payment of accounts payable and accrued liabilities, especially pertaining to capital expenditures were also factors in deriving net cash flows from operations.

Overall, net cash used in investing activities decreased from the previous year from $12,417,000 for the year ended March 31, 2013 to $10,903,000 for the year ended March 31, 2014. The decrease in cash used relates primarily to decreased  expenditures on the acquisition of producing properties, primarily on horizontal Bakken wells in the Williston Basin where for a large portion of the year just one drilling rig was operating in the Banks field as compared to multiple rigs in the prior fiscal period.
 
Net cash provided by financing activities for the years ended March 31, 2014 and 2013 was $4,953,000 and $3,952,000, respectively, related to borrowings on our credit facility, offset by certain fees and costs for that borrowing.

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, 2014, we incurred capital expenditures of $12,830,000 on various projects. This compares to $13,900,000 for the year ended March 31, 2013. During the year ended March 31, 2014, capital expenditures were comprised of drilling and completions of wells producing as of year-end (54%), drilling of wells to be completed as of calendar year-end (43%), and leaseholds (3%). The majority (88%) of capital expenditures occurred in the Williston Basin. The remainder was spent in other areas on property improvements and leasehold acreage.

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.
 

 
21

 
Divestitures/Abandonments

For the year ended March 31, 2014, we divested our interests in a salt water disposal well located in North Dakota for proceeds of $292,000.  We plugged and abandoned one well located in Nebraska during the year ended March 31, 2014.  The net costs associated with the plugging and abandonment amounted to $56,000.

Impact of Inflation and Pricing

We deal primarily in U.S. dollars. Inflation has not had a material impact on us 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.  See Note 7 to the consolidated financial statements.
 
 
 
22

 
 
Results of Operations

Selected Financial Information

The following provides selected financial information and averages for the years ended March 31, 2014 and 2013. Certain prior year amounts may have been reclassified to conform to the current presentation. 

 
Year Ended
March 31,
 
 
2014
 
2013
 
         
Revenue
           
   Oil
 
$
15,633,000
   
$
10,283,000
 
   Gas 1
   
1,807,000
     
699,000
 
Total revenue 2
   
17,440,000
     
10,982,000
 
                 
Total production expense 3
   
3,957,000
     
3,453,000
 
                 
Gross profit
 
$
13,483,000
   
$
7,529,000
 
                 
Depletion expense
 
$
3,768,000
   
$
1,951,000
 
                 
                 
Sales volume 4
               
   Oil (Bbls)
   
173,880
     
122,655
 
   Gas (Mcfs)
   
189,933
     
107,076
 
   BOE
   
205,536
     
140,501
 
                 
Average sales price 5
               
   Oil (per Bbl)
 
$
89.91
   
$
83.84
 
   Gas (per Mcf)  6
 
$
9.51
   
$
6.53
 
   BOE
 
$
84.85
   
$
78.16
 
                 
Average per BOE 4, 5, 7
               
   Production expense 5
 
$
19.25
   
$
24.58
 
   Gross profit 5
 
$
65.60
   
$
53.59
 
   Depletion expense 5
 
$
18.33
   
$
13.89
 
__________________
    1
Amount includes NGL revenue.  For the years ended March 31, 2014 and 2013, the NGL revenue included in the gas revenue amount is $808,000 and $221,000, respectively.
 
    2
Amount does not include water service and disposal revenue.  For the years ended March 31, 2014 and 2013, this revenue amount is net of $74,000 and $396,000, respectively, in well service and water disposal revenue, which would otherwise total $17,514,000 and $11,378,000, respectively, in revenue.
    3
Overall lifting cost (oil and gas production costs and the cost of workovers)
 
    4
Estimates of volumes are inherent in reported volumes to coincide with revenue accruals as a result of the timing of sales information reporting by third party operators.
 
    5
Averages calculated based upon non-rounded figures.
 
    6
Average gas sales price per Mcf is calculated by dividing total gas and NGL revenue by the gas sales volume per Mcf.  For the years ended March 31, 2014 and 2013, gas sales price per Mcf, exclusive of NGL revenues, was $5.26 per Mcf and $4.46 per Mcf, respectively.
    7
Per equivalent barrel (6 thousand cubic feet, “Mcf”, of gas is equivalent to 1 barrel, “Bbl”, of oil)

 

 
23

 
 
The Year Ended March 31, 2014 Compared with the Year Ended March 31, 2013

Overview. Net income for the year ended March 31, 2014, was $3,939,000 compared to $1,780,000 for the year ended March 31, 2013 a 121% increase.  Increases in sales volumes, coupled with increases in the sales price per barrel of oil equivalent (“BOE”), offset by higher production costs and DD&A expense, resulted in the increase in net income.

Revenues. Oil and natural gas sales revenue increased $6,458,000 (59%) from $10,982,000 for the year ended March 31, 2013 to $17,440,000 for the year ended March 31, 2014, due to an overall 9% higher realized price per BOE and a 46% overall increase in sales volumes.

Volumes and Prices. On an equivalent barrel basis, sales were 206,000 BOE for the year ended March 31, 2014 compared to 141,000 BOE for the year ended March 31, 2013, a 46% increase.

Oil sales volumes increased 42% from 122,655 barrels for the year ended March 31, 2013 to 173,880 barrels for the year ended March 31, 2014, while the average price per barrel increased 7% from $83.84 for the year ended March 31, 2013 to $89.91 for the year ended March 31, 2014. The rise in oil volumes resulted from production from newly producing wells offset, partially, by declines in existing wells.

Gas sales volumes increased 77% from 107,076 Mcf for the year ended March 31, 2013 to 189,933 Mcf for the year ended March 31, 2014, while the average price per Mcf increased 46%, from $6.53 for the year ended March 31, 2013 to $9.51 for the year ended March 31, 2014. The increase in volumes is primarily related to newly producing wells, coupled with a higher percentage of gas being sold from existing wells as midstream infrastructure is expanded, offset partially by declines in existing wells.

Production Expenses. Production expenses are comprised of the following items:

   
Year Ended
March 31,
 
   
2014
   
2013
 
             
Lease operating expenses
 
$
2,920,000
   
$
2,563,000
 
Workover expenses
   
689,000
     
816,000
 
Transportation and other expenses
   
348,000
     
74,000
 
                 
   
$
3,957,000
   
$
3,453,000
 

Oil and gas production expense increased $504,000 (15%) for the year ended March 31, 2014, as compared to the year ended March 31, 2013. The two principal components of oil and gas production expense are routine lease operating expenses (“LOE”) and workovers. Routine expenses typically include such items as daily well maintenance, utilities, fuel, water disposal and minor surface equipment repairs. Workovers primarily include downhole repairs and are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their associated costs can be significant. Therefore, workovers account for more dramatic fluctuations in oil and gas production expense from period to period.

LOE and transportation and other expenses increased $357,000 (14%) and $274,000 (370%), respectively, for the year ended March 31, 2014, as compared to the year ended March 31, 2013. Workover expense decreased $127,000 (16%) from $816,000 for the year ended March 31, 2013 to $689,000 for the year ended March 31, 2014.
 
 
 
 
24

 

The overall lifting cost per BOE decreased $5.33 (22%) from $24.58 for the year ended March 31, 2013 to $19.25 for the year ended March 31, 2014. This decrease resulted from those costs being spread over larger reported BOE volumes. 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 increased $1,864,000 (92%) from $2,017,000 for the year ended March 31, 2013 to $3,881,000 for the year ended March 31, 2014 due to the addition of numerous high-cost North Dakota wells to the depletion base. These newer North Dakota wells reflect a higher investment per well than the remaining, un-expensed depletion base associated with our Legacy properties. Correspondingly, depletion expense per BOE increased from $13.89 for the year ended March 31, 2013 to $18.33 for the year ended March 31, 2014.

General and administrative (“G&A”) expense increased $3,000 (0.1%) from $2,625,000 for the year ended March 31, 2013, to $2,628,000 for the year ended March 31, 2014. This slight increase in costs is comprised primarily of increases in compensation-related expenses.  As a percent of total sales revenue, G&A expense decreased from 23% for the year ended March 31, 2013 to 15% for the year ended March 31, 2014.
 
Income Tax. For the year ended March 31, 2014, we recorded income tax expense of $1,125,000. This amount consisted of a current period benefit of $390,000, resulting from the utilization of previously accumulated net operating losses, and deferred tax expense of $1,515,000. Our effective income tax rate increased from 14.5% for the year ended March 31, 2013 to 22.2% for the year ended March 31, 2014. Our effective income tax rate was higher for the year ended March 31, 2014 primarily due to a decrease in the percentage of current year excess depletion deduction between the comparable periods.
 
Critical Accounting Policies and Estimates

See Note 1 to the consolidated financial statements.

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.  This ASU requires us to disclose both net and gross information about assets and liabilities that have been offset. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented.  We are required to implement this guidance effective for the first quarter of fiscal 2014.  The adoption of ASU 2011-11 did not have a material impact on our consolidated financial statements.

In July 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”).  ASU 2013-11 addresses the diversity in practice that exists for the balance sheet presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit,  be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. ASU No. 2013-11 is effective for our fiscal quarter ending June 30, 2014. ASU 2013-11 impacts balance sheet presentation only. We are currently evaluating the impact of the new rule, but believe the balance sheet impact will not be material.

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.
 
 
25

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As a “smaller reporting company,” we are not required to provide the information.
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Earthstone Energy, Inc.
Table of Contents
Consolidated Financial Statements
and Accompanying Notes
March 31, 2014 and 2013

   
Page
   
Re   Report of Independent Registered Public Accounting Firm – EKS&H LLLP
   
27
 
Consolidated Balance Sheets
   
28-29
 
Consolidated Statements of Operations
   
30
 
Consolidated Statements of Shareholders’ Equity
   
31
 
Consolidated Statements of Cash Flows
   
32
 
Notes to Consolidated Financial Statements
   
33-46
 
 

 
 
26

 

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, 2014 and 2013, 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 audits 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, 2014 and 2013, 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.
 
 
/s/ EKSH LLLP
 
Denver, Colorado
June 10, 2014
 
 
 
27

 

Earthstone Energy, Inc.
Consolidated Balance Sheets
Page 1 of 2
 
   
March 31,
   
March 31,
 
   
2014
   
2013
 
             
Assets
Current assets:
           
Cash and cash equivalents
 
$
2,671,000
   
$
2,180,000
 
Accounts receivable:
               
Oil and gas sales
   
3,895,000
     
2,753,000
 
Joint interest and other receivables, net of allowance of ($15,000) and ($38,000), respectively
   
758,000
     
630,000
 
Other current assets
   
1,043,000
     
814,000
 
                 
Total current assets
   
8,367,000
     
6,377,000
 
                 
Oil and gas properties, full cost method:
               
Proved properties
   
67,186,000
     
53,265,000
 
Unproved properties
   
773,000
     
2,156,000
 
Accumulated depletion and impairment
   
(31,496,000
)
   
(27,729,000
)
                 
Net oil and gas properties
   
36,463,000
     
27,692,000
 
                 
Support equipment and other non-current assets, net of accumulated depreciation of ($514,000) and ($416,000), respectively
   
791,000
     
611,000
 
                 
Total non-current assets
   
37,254,000
     
28,303,000
 
                 
Total assets
 
$
45,621,000
   
$
34,680,000
 
 
See accompanying notes to consolidated financial statements
 
 
28

 
 
Earthstone Energy, Inc.
Consolidated Balance Sheets
Page 2 of 2
 
   
March 31,
   
March 31,
 
   
2014
   
2013
 
             
Liabilities and Shareholders’ Equity
Current liabilities:
           
Accounts payable
 
$
430,000
   
$
1,631,000
 
Accrued liabilities
   
5,243,000
     
3,971,000
 
                 
Total current liabilities
   
5,673,000
     
5,602,000
 
                 
Long-term liabilities:
               
Long-term debt
   
9,000,000
     
4,000,000
 
Deferred tax liability
   
4,486,000
     
2,971,000
 
Asset retirement obligation, less current portion
   
2,068,000
     
1,809,000
 
                 
Total long-term liabilities
   
15,554,000
     
8,780,000
 
                 
Total liabilities
   
21,227,000
     
14,382,000
 
                 
Shareholders’ equity:
               
Preferred shares, $0.001 par value, 600,000 authorized and none issued or outstanding
   
-
     
-
 
Common shares, $0.001 par value, 6,400,000 shares authorized and 1,753,000 and 1,802,000 shares issued, respectively
   
18,000
     
18,000
 
Additional paid-in capital
   
23,436,000
     
23,278,000
 
Treasury stock, at cost, 24,000 and 82,000 shares, respectively
   
(458,000
)
   
(457,000
)
Accumulated earnings (deficit)
   
1,398,000
     
(2,541,000
)
                 
Total shareholders’ equity
   
24,394,000
     
20,298,000
 
                 
Total liabilities and shareholders’ equity
 
$
45,621,000
   
$
34,680,000
 
 
See accompanying notes to consolidated financial statements
 
 
29

 

Earthstone Energy, Inc.
Consolidated Statements of Operations
 
   
Year ended March 31,
 
   
2014
   
2013
 
Revenues:
           
Oil and gas sales
 
$
17,440,000
   
$
10,982,000
 
Well service and water-disposal revenue
   
74,000
     
396,000
 
                 
Total revenues
   
17,514,000
     
11,378,000
 
                 
Expenses:
               
Oil and gas production
   
3,957,000
     
3,453,000
 
Production tax
   
1,582,000
     
971,000
 
Well service and water-disposal
   
100,000
     
94,000
 
Depletion and depreciation
   
3,881,000
     
2,017,000
 
Accretion of asset retirement obligation
   
202,000
     
177,000
 
General and administrative
   
2,628,000
     
2,625,000
 
                 
Total expenses
   
12,350,000
     
9,337,000
 
                 
Income from operations
   
5,164,000
     
2,041,000
 
                 
Other income (expense):
               
Interest and other income
   
73,000
     
62,000
 
Interest and other expenses
   
(173,000
)
   
(21,000
)
                 
Total other income (expense)
   
(100,000
   
41,000
 
                 
Income before income tax
   
5,064,000
     
2,082,000
 
                 
Current income tax (benefit) expense
   
(390,000
   
62,000
 
Deferred income tax expense
   
1,515,000
     
240,000
 
                 
Total income tax expense
   
1,125,000
     
302,000
 
                 
Net income
 
$
3,939,000
   
$
1,780,000
 
                 
Per share amounts:
               
Basic
 
$
2.27
   
$
1.03
 
Diluted
 
$
2.27
   
$
1.03
 
                 
Weighted average common shares outstanding:
               
Basic
   
1,731,812
     
1,720,712
 
Diluted
   
1,731,812
     
1,720,712
 
 
See accompanying notes to consolidated financial statements
 
 
30

 

Earthstone Energy, Inc.
Consolidated Statements of Shareholders' Equity
Years ended March 31, 2014 and 2013
 
               
Additional
               
Accumulated
       
   
Common shares
   
paid-in
   
Treasury shares
   
earnings/
       
   
Shares
   
Amount
   
capital
   
Shares
   
Amount
   
(deficit)
   
Total
 
                                           
Balances at March 31, 2012
   
1,788,000
   
$
18,000
   
$
23,108,000
     
(82,000
)
 
$
(457,000
)
 
$
(4,321,000
)
 
$
18,348,000
 
                                                         
Share-based compensation
   
14,000
     
-
     
170,000
     
-
     
-
     
-
     
170,000
 
Net income
   
-
     
-
     
-
     
-
     
-
     
1,780,000
     
1,780,000
 
                                                         
Balances at March 31, 2013
   
1,802,000
   
$
18,000
   
$
23,278,000
     
(82,000
)
 
$
(457,000
)
 
$
(2,541,000
)
 
$
20,298,000
 
                                                         
Purchase of treasury shares
   
-
     
-
     
-
     
-
     
(1,000
   
-
     
(1,000
Share-based compensation
   
12,000
     
-
     
158,000
     
-
     
-
     
-
     
158,000
 
Reclassification of shares held in treasury
   
(58,000
)
   
-
     
-
     
58,000
     
-
     
-
     
-
 
Forfeitures
   
(3,000
)
   
-
     
-
     
-
     
-
     
-
     
-
 
Net income
   
-
     
-
     
-
     
-
     
-
     
3,939,000
     
3,939,000
 
                                                         
Balances at March 31, 2014
   
1,753,000
   
$
18,000
   
$
23,436,000
     
(24,000
)
 
$
(458,000
)
 
$
1,398,000
   
$
24,394,000
 
 
See accompanying notes to consolidated financial statements
 
 
 
31

 

Earthstone Energy, Inc.
Consolidated Statements of Cash Flows
 
   
Year ended March 31,
 
   
2014
   
2013
 
Cash flows from operating activities:
           
Net income
 
$
3,939,000
   
$
1,780,000
 
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depletion and depreciation
   
3,881,000
     
2,017,000
 
Deferred income tax expense
   
1,515,000
     
240,000
 
Accretion of asset retirement obligation
   
202,000
     
177,000
 
Share-based compensation
   
158,000
     
170,000
 
Amortization of deferred financing costs
   
13,000
     
2,000
 
Change in:
               
Accounts receivable
   
(1,270,000
)
   
(904,000
)
Other current assets
   
(501,000
)
   
(74,000
)
Accounts payable and accrued liabilities
   
(1,496,000
   
459,000
 
                 
Net cash provided by operating activities
   
6,441,000
     
3,867,000
 
                 
Cash flows from investing activities:
               
Oil and gas properties
   
(10,934,000
)
   
(12,243,000
)
Proceeds from sale of oil and gas property and equipment
   
292,000
     
-
 
Purchases of support equipment and other non-current assets
   
(261,000
)
   
(174,000
)
                 
Net cash used in investing activities
   
(10,903,000
)
   
(12,417,000
)
                 
Cash flows from financing activities:
               
Borrowings on long-term debt
   
5,000,000
     
4,000,000
 
Deferred financing costs
   
(46,000
)
   
(48,000
Purchase of treasury shares
   
(1,000
   
-
 
                 
Net cash provided by financing activities
   
4,953,000
     
3,952,000
 
                 
Cash and cash equivalents:
               
Net increase (decrease) in cash and cash equivalents
   
491,000
     
(4,598,000
Cash and cash equivalents, beginning of year
   
2,180,000
     
6,778,000
 
                 
Cash and cash equivalents, end of year
 
$
2,671,000
   
$
2,180,000
 
                 
Supplemental disclosure of cash flow information:
               
Cash paid for interest
 
$
154,000
   
$
15,000
 
Cash paid for income tax
 
$
1,000
   
$
341,000
 
Non-cash:
               
Increase in oil and gas property due to asset retirement obligation
 
$
85,000
   
$
102,000
 
Accrued capital expenditures
 
$
1,539,000
   
$
1,546,000
 
Prepaid capital expenditures
 
$
272,000
   
$
9,000
 
 
See accompanying notes to consolidated financial statements
 
 
32

 
Earthstone Energy, Inc.
Notes to Consolidated Financial Statements
March 31, 2014
 
1. Summary of Significant Accounting Policies
 
Organization and Nature of Operations.  Earthstone Energy, Inc. (the “Company”) 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 North Dakota and Montana portions of the Williston Basin and South Texas.
 
On May 15, 2014 the Company and Oak Valley, entered into an Exchange Agreement. The Exchange Agreement provides that, upon the terms and subject to the conditions set forth in the Exchange Agreement, Oak Valley will contribute to the Company the membership interests of its three subsidiaries, each a Texas limited liability company, inclusive of producing assets, undeveloped acreage and an estimated $138 million of cash, in exchange for the issuance of approximately 9.1 million shares of the Company’s common stock. Following the Exchange, current Earthstone stockholders will own 16% of the Company's outstanding Common Stock and Oak Valley will own 84% of the Company's outstanding Common Stock. The Exchange Agreement has been approved by the board of directors of Earthstone and the board of managers of Oak Valley.  See Note 12 below for further information.
 
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 U.S. Securities and Exchange Commission (“SEC”) to use “plain English” in public filings, the Company uses 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 the notes to the audited consolidated financial statements, they are in reference only to the corporation, Earthstone Energy, Inc. and its subsidiaries, and are not used in reference to the Board, 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.  The Company derives 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.  Collection of the revenue may vary depending on the status of wells or the performance of the operator.  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 non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.
 
 
 
33

 
 
Capitalized costs are subject to a ceiling test, as prescribed by 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, 2014 and 2013, 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 ten percent.

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 the Company or other parties.
 
Capitalized costs of oil and gas properties, 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.
 
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 spud 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 Tax.  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 uncertain tax positions were identified as of any date on or before March 31, 2014.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of March 31, 2014, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 9 below for further information.
 
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. Included in our basic and diluted earnings per share calculations are the unvested common shares issued to employees and directors of the Company. Inclusion of the unvested common shares in basic and diluted earnings per share has not resulted in a material variance between basic and diluted earnings per share.
 
Cash and Cash Equivalents.  All highly liquid investments with original maturities of 90 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 (“FASB”), 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, and long-term debt, 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.
 
 
 
 
34

 
 
 
As discussed in Note 6, the Company incurred asset retirement obligations of $85,000 for the year ended March 31, 2014 and asset retirement obligations of $69,000 and an additional $33,000 related to revisions in estimated liabilities for the year ended March 31, 2013, 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.  The Company had no hedging activities in the years ended March 31, 2014 and 2013.  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 the Company is 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 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.  
 
Commitments.  The Company is committed to $9,880 per month plus maintenance fees on a 7,000 square foot office space located in downtown Denver, Colorado.  The lease term ends on April 30, 2016.  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, 2014 and 2013 were as follows:
 
   
2014
   
2013
 
             
Valero Energy Corp.
   
11
%
   
17
%
Plains Marketing LP
   
6
%
   
10
%
Total
   
17
%
   
27
%
 
For the years ended March 31, 2014 and 2013, approximately 80% and 65%, 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 25 different companies who operate these wells.  These 25 companies may, unbeknownst to the Company, market to one or more of the same purchasers to whom the Company sells directly.  Therefore, the Company is unable to ascertain the total extent of combined purchaser concentration.  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 8 below for information.
 
Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP 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.
 
 
 
35

 
 
 
Recent Accounting Pronouncements.  In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.  This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented.  The Company was required to implement this guidance effective for the first quarter of fiscal 2014.  The adoption of ASU 2011-11 did not have a material impact on its consolidated financial statements.
 
In July 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”).  ASU 2013-11 addresses the diversity in practice that exists for the balance sheet presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. ASU No. 2013-11 is effective for the Company’s fiscal quarter ending June 30, 2014. ASU 2013-11 impacts balance sheet presentation only. The Company is currently evaluating the impact of the new rule but believes the balance sheet impact will not be material.
 
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 the Company’s financial position, results of operations, or cash flows.
 

 
 
36

 
 

2. Other Current Assets
 
Other current assets as of March 31, 2014 and 2013 consisted of:
 
   
2014
   
2013
 
             
Prepaid income tax
 
$
379,000
   
$
112,000
 
Lease and well equipment inventory
   
310,000
     
371,000
 
Drilling and completion cost prepayments
   
223,000
     
210,000
 
Prepaid insurance premiums
   
91,000
     
88,000
 
Other current assets
   
40,000
     
33,000
 
                 
Total other current assets
 
$
1,043,000
   
$
814,000
 
 
Lease and well equipment inventory included in other current assets represents well site production equipment owned by the Company that has been removed from wells that the Company operates.  This occurs when the Company plugs a well or replaces 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 the Company from further transferring serviceable equipment to other wells that the Company operates, on an as needed basis.  During the year, the Company impaired approximately $61,000 of inventory to production expense.
 
Drilling and completion cost prepayments represent cash expenditures advanced by the Company 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 as of March 31, 2014 and 2013 consisted of:
 
   
2014
   
2013
 
             
Support equipment and lease and well equipment inventory
 
$
590,000
   
$
500,000
 
Plugging bonds
   
122,000
     
65,000
 
Deferred financing costs
   
79,000
     
46,000
 
                 
Total other non-current assets
 
$
791,000
   
$
611,000
 
 
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 $114,000 and $66,000 for the years ended March 31, 2014 and 2013, 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 the Company operates.  This equipment inventory represents well site production equipment that the Company owns that has either been purchased or has been removed from wells that the Company operates.  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 the Company to third parties who supply plugging bonds to federal and state agencies where the Company operates wells.  
 
Deferred financing costs represent fees and expenses incurred in connection with the origination of the Company’s credit facility in December 2012. These costs will be amortized on a straight-line basis over the five year term of the facility.
 
 
 
37

 

 
4. Accrued Liabilities
 
Other current liabilities as of March 31, 2014 and 2013 consisted of:
 
   
2014
   
2013
 
             
Accrued operations payable
 
$
4,209,000
   
$
2,933,000
 
Accrued compensation
   
411,000
     
429,000
 
Short-term asset retirement obligation
   
317,000
     
296,000
 
Accrued income tax payable and other
   
180,000
     
213,000
 
Revenue and production taxes payable
   
126,000
     
100,000
 
                 
Total accrued liabilities
 
$
5,243,000
   
$
3,971,000
 

5. Long-Term Debt
 
On December 21, 2012 the Company entered into a $25 million senior secured revolving bank credit facility (the “Credit Facility”) with the Bank of Oklahoma (the “Bank”).  The initial borrowing base on the Credit Facility was $6 million.  The maturity date of the Credit Facility is December 21, 2017 and provides for a borrowing base subject to redetermination semi-annually each June and December and for certain unscheduled redeterminations.  The Credit Facility is secured by mortgages on primarily all of the Company’s properties and an assignment of all the proceeds from severed and extracted hydrocarbons from the properties described in the mortgages.  Until further notice, the Bank has suspended their right to receive the proceeds directly.
 
Effective September 10, 2013, the Company entered into a Waiver and First Amendment to Credit Agreement (the “Amended Credit Facility”) with the Bank in connection with a semiannual redetermination of the borrowing base.  The redetermination resulted in an increase in the borrowing base from $6 million under the initial Credit Facility to $12 million under the Amended Credit Facility, which amount is subject to redetermination.  The Company’s ability to remain in compliance with the financial covenants may be affected by events and other factors beyond the Company’s control, including market prices for the Company’s oil and gas and the rate at which the operators of projects drill in which the Company participates. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect the Company’s liquidity by rendering the Company unable to borrow further under the Amended Credit Facility.
 
The Credit Facility contains negative covenants that limit the Company's ability, among other things, to pay any cash dividends, incur additional indebtedness, sell assets, enter into hedging contracts, change the nature of its business or operations, merge, consolidate or make investments.  In addition, the Company is required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0.  As of March 31, 2014, the Company was in compliance with all of the financial covenants under the Credit Facility. Should our Exchange Agreement with Oak Valley close we would require the consent of the Bank.
 
Payments of interest are due quarterly in arrears at prime plus 0.75% to 1.75% or LIBOR plus 1.75% to 2.75%, depending on the Company's level of borrowing and election at the date of borrowing.  Commitment fees on the unused amounts of the Credit Facility are due quarterly at rates from 0.35% to 0.50% on the unused amounts of the Credit Facility.  At closing, the Company paid a borrowing base fee of $30,000, or 0.5%, on the $6 million borrowing base.  An additional borrowing base fee of $30,000, or 5%, on the increase in borrowing base of $6 million under the Amended Credit Facility was paid by the Company during the year ended March 31, 2014.  These costs have been recorded as deferred financing costs and will be amortized over the term of the facility.  Deferred financing fees in the amount of $34,000 related to legal expenses and other costs to originate the Credit Facility and the Amended Credit Facility have been recorded.  These costs will be amortized over the term on the facility.  Amortization of deferred financing fees in the amount of $13,000 was recorded during the year ended March 31, 2014.  Additional borrowing base fees may be payable upon future increases in the borrowing base, if any.  As of March 31, 2014, the Company had an outstanding balance under the Credit Facility of $9 million.  
 
6. Asset Retirement Obligation
 
For the purpose of determining the fair value of the asset retirement obligation incurred during the year ended March 31, 2014, the Company assumed an inflation rate of 4.07%, an estimated average asset life of 30 years, and a credit adjusted risk free interest rate of 7.85%.
 
 
38

 
 
The following reconciles the value of the asset retirement obligation for the periods presented.  This included a short-term obligation of $317,000 and $296,000 as of March 31, 2014 and 2013, respectively, which was a component of accrued liabilities on the balance sheets:
 
   
2014
   
2013
 
             
Asset retirement obligation, beginning of year
 
$
2,105,000
   
$
1,826,000
 
Liabilities settled
   
(7,000
   
-
 
Liabilities incurred
   
85,000
     
69,000
 
Revisions in estimated liabilities
   
-
     
33,000
 
Accretion
   
202,000
     
177,000
 
                 
Asset retirement obligation, end of year
   
2,385,000
     
2,105,000
 
                 
Less Current portion
   
(317,000
)
   
(296,000
)
                 
Asset retirement obligation, less current portion
 
$
2,068,000
   
$
1,809,000
 
 
7.  Commitments
 
Office rent expense was approximately $202,000 and $158,000 for the years ended March 31, 2014 and 2013, respectively (including building maintenance charges).  The Company is committed to a total of $247,000 for the remaining term on its 7,000 square foot office space located in downtown Denver, Colorado, ending April 30, 2016.
 
 
8.  Shareholders' Equity
 
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.  Since inception, the Company has not issued any preferred shares.
 
 
 
39

 

 
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, 2014, was 1,753,000 common shares.
 
Share-Based Compensation.  On March 8, 2007, the Board 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, 2014, 6,525 shares of common stock reserved for issuance under the Plan were authorized for issuance.  Accordingly, as of March 31, 2014, 3,661 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, 2014, for each non-employee director was as follows: Robertson – 3,894 shares; Rodgers – 3,894; and Calerich – 3,938.  In addition, each of the three independent directors was granted 1,679 shares of restricted stock on April 1, 2014, 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.
 
A summary of the status of the Company’s non-vested shares under the Director Compensation Plan as of March 31, 2014 and 2013, and changes during the years ended on those dates is presented below:
 
   
2014
   
2013
 
         
Weighted
         
Weighted
 
         
Average
         
Average
 
         
Grant
         
Grant
 
         
Date Fair
         
Date Fair
 
   
Shares
   
Value
   
Shares
   
Value
 
                         
Non-vested shares, beginning of year
   
11,755
   
$
207,000
     
14,779
   
$
186,000
 
                                 
Granted
   
6,525
     
108,000
     
4,929
     
108,000
 
Vested
   
(6,554
)
   
(99,000
)
   
(7,953
)