EARTHSTONE ENERGY INC - Quarter Report: 2012 September (Form 10-Q)

este_10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2012

o	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 0-7914

(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 1900, Denver, Colorado		80202-3619
(Address of principal executive office)		(Zip Code)

(303) 296-3076

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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

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

Check whether the issuer is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Shares of common stock outstanding on November 13, 2012: 1,720,712

EARTHSTONE ENERGY, INC.

FORM 10-Q

INDEX

	PART I. FINANCIAL INFORMATION	Page

Item 1.	Financial Statements		4

	Condensed Consolidated Balance Sheets:
	September 30, 2012 (Unaudited) and March 31, 2012		4

	Condensed Consolidated Statements of Operations:
	Three Months and Six Months Ended September 30, 2012 and 2011(Unaudited)		6

	Condensed Consolidated Statements of Cash Flows:
	Six Months Ended September 30, 2012 and 2011 (Unaudited)		7

	Notes to Unaudited Condensed Consolidated Financial Statements:
	September 30, 2012		8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		12

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		20

Item 4.	Controls and Procedures		20

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		21

Item 1A.	Risk Factors		21

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		21

Item 3.	Defaults Upon Senior Securities		21

Item 4.	Mine Safety Disclosures		21

Item 5.	Other Information		21

Item 6.	Exhibits		22

	Signatures		23

FORWARD-LOOKING STATEMENTS

This Current Report on Form 10-Q, 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, assumptions 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 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;

●	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;

●	exploitation, development, production and exploration results, including mechanical failure;

●	the estimated costs of asset retirement obligations, 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 and 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.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

	September 30,			March 31,
	2012			2012
	(Unaudited)

ASSETS
Current assets:
Cash and cash equivalents	$	2,576,000		$	6,778,000
Accounts receivable:
Oil and gas sales		2,484,000			2,389,000
Joint interest and other receivables		162,000			90,000
net of allowance of (60,000) and (60,000), respectively
Other current assets		993,000			749,000

Total current assets		6,215,000			10,006,000

Oil and gas property, full cost method:
Proved property		43,257,000			37,112,000
Unproved property		4,660,000			4,409,000
Accumulated depletion and impairment		(26,503,000	)		(25,778,000	)

Net oil and gas property		21,414,000			15,743,000

Support equipment and other non-current assets		460,000			457,000
net of accumulated depreciation of (385,000) and (383,000), respectively

Total non-current assets		21,874,000			16,200,000

Total assets	$	28,089,000		$	26,206,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

	September 30,			March 31,
	2012			2012
	(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	383,000		$	824,000
Accrued liabilities		4,008,000			2,610,000

Total current liabilities		4,391,000			3,434,000

Long-term liabilities:
Deferred tax liability		2,805,000			2,731,000
Asset retirement obligation, less current portion		1,693,000			1,693,000

Total long-term liabilities		4,498,000			4,424,000

Total liabilities		8,889,000			7,858,000

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 1,802,000 and 1,788,000 shares issued, respectively		18,000			18,000
Additional paid-in capital		23,204,000			23,108,000
Treasury stock, at cost, 82,000 shares		(457,000	)		(457,000	)
Accumulated deficit		(3,565,000	)		(4,321,000	)

Total shareholders’ equity		19,200,000			18,348,000

Total liabilities and shareholders’ equity	$	28,089,000		$	26,206,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended					Six Months Ended
	September 30,					September 30,
	2012			2011		2012			2011
Revenues:
Oil and gas sales	$	2,700,000		$	2,505,000	$	4,920,000		$	4,985,000
Well service and water disposal revenue		109,000			40,000		236,000			85,000

Total revenues		2,809,000			2,545,000		5,156,000			5,070,000

Expenses:
Oil and gas production		823,000			826,000		1,657,000			1,621,000
Production tax		262,000			200,000		458,000			338,000
Well service and water disposal		19,000			-		42,000			6,000
Depletion and depreciation		461,000			229,000		755,000			425,000
Accretion of asset retirement obligation		44,000			41,000		87,000			82,000
General and administrative		627,000			507,000		1,308,000			949,000

Total expenses		2,236,000			1,803,000		4,307,000			3,421,000

Income from operations		573,000			742,000		849,000			1,649,000

Other income (expense):
Interest and other income		6,000			60,000		8,000			67,000
Interest and other expenses		(1,000	)		-		(1,000	)		(3,000	)

Total other income		5,000			60,000		7,000			64,000

Income before income tax		578,000			802,000		856,000			1,713,000

Current income tax expense		14,000			32,000		26,000			95,000
Deferred income tax expense		78,000			42,000		74,000			225,000

Total income tax expense		92,000			74,000		100,000			320,000

Net income	$	486,000		$	728,000	$	756,000		$	1,393,000

Per share amounts:
Basic	$	0.28		$	0.43	$	0.44		$	0.81
Diluted	$	0.28		$	0.43	$	0.44		$	0.81

Weighted average common shares outstanding:
Basic		1,720,712			1,710,804		1,720,712			1,711,768
Diluted		1,720,712			1,710,804		1,720,712			1,711,768

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	756,000		$	1,393,000
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion and depreciation		755,000			425,000
Deferred income tax expense		74,000			225,000
Accretion of asset retirement obligation		87,000			82,000
Share-based compensation		96,000			44,000
Change in:
Accounts receivable, net		(167,000	)		201,000
Other current assets		(350,000	)		30,000
Accounts payable, accrued and other liabilities		(733,000	)		(205,000	)

Net cash provided by operating activities		518,000			2,195,000

Cash flows from investing activities:
Oil and gas property		(4,683,000	)		(2,975,000	)
Purchases of support equipment and other non-current assets		(37,000	)		(50,000	)

Net cash (used in) investing activities		(4,720,000	)		(3,025,000	)

Cash flows from financing activities:
Purchase of treasury shares		-			(84,000	)

Net cash (used in) financing activities		-			(84,000	)

Cash and cash equivalents:
Net decrease in cash and cash equivalents		(4,202,000	)		(914,000	)
Cash and cash equivalents, beginning of year		6,778,000			4,051,000

Cash and cash equivalents, end of period	$	2,576,000		$	3,137,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	1,000		$	-
Cash paid for income tax	$	341,000		$	1,000
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	35,000		$	23,000
Accrued capital expenditures	$	1,572,000		$	719,000
Prepaid capital expenditures transferred to oil and gas property	$	106,000		$	56,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

September 30, 2012

1. Basis of Presentation

The accompanying interim financial statements of Earthstone Energy, Inc. (formerly Basic Earth Science Systems, Inc.) are unaudited. However, in the opinion of management, the interim data includes any applicable adjustments necessary for a fair presentation of the financial and operational results for the interim period according to generally accepted accounting principles in the United States of America (“U.S. GAAP”).

At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Earthstone Energy, Inc. and its wholly-owned subsidiary. When such terms are used in this manner throughout the notes to the unaudited condensed 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 of Directors, corporate officers, management, or any individual employee or group of employees.

The financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are adequate to make the information not misleading and suggest that these financial statements be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the previous fiscal year-end.

Further, the results of operations for the three months and six months covered by this report, are not necessarily indicative of the operating results that may be expected for the year.

Fair Value Measurements. The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities, all of which are considered to be representative of their fair market value, due to the short-term and highly liquid nature of these instruments.

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.

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

2. Other Assets

	09/30/12		03/31/12
	(Unaudited)
Drilling and completion cost prepayments	$	428,000	$	230,000
Lease and well equipment inventory		323,000		412,000
Prepaid insurance premiums		40,000		73,000
Prepaid income tax		146,000		-
Other current assets		56,000		34,000

Total other current assets	$	993,000	$	749,000

3. Accrued Liabilities

	09/30/12		03/31/12
	(Unaudited)
Accrued operations payable	$	2,953,000	$	1,472,000
Accrued compensation		430,000		445,000
Accrued income tax payable and other		230,000		393,000
Revenue and production taxes payable		141,000		167,000
Short term asset retirement obligation		254,000		133,000

Total accrued liabilities	$	4,008,000	$	2,610,000

4. Oil and Gas Properties

	09/30/12			03/31/12
	(Unaudited)
Proved properties	$	43,257,000		$	37,112,000
Unproved properties		4,660,000			4,409,000
Less Accumulated depletion and impairment		(26,503,000	)		(25,778,000	)

Net oil and gas property	$	21,414,000		$	15,743,000

The company recorded $6,145,000 as proved property costs primarily related to tangible completion costs incurred in North Dakota.

The company recorded $251,000 as unproved property costs primarily related to intangible and tangible drilling costs in North Dakota.

5. Income Tax

The provision for income tax is comprised of:	Three Months Ended September 30,				Six Months Ended September 30,
	2012		2011		2012		2011
	(Unaudited)		(Unaudited)		(Unaudited)		(Unaudited)
Current:
Federal	$	12,000	$	29,000	$	23,000	$	85,000
State		2,000		3,000		3,000		10,000
Total current income tax		14,000		32,000		26,000		95,000

Deferred:
Federal		73,000		40,000		69,000		210,000
State		5,000		2,000		5,000		15,000
Total deferred income tax		78,000		42,000		74,000		225,000

Income tax expense	$	92,000	$	74,000	$	100,000	$	320,000

A reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision for the three months and six months ended is as follows:

	Three Months Ended September 30,						Six Months Ended September 30,
	2012			2011			2012			2011
	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
Federal tax at statutory rate	$	197,000		$	273,000		$	291,000		$	583,000
State taxes, net of federal benefit		7,000			11,000			7,000			28,000
Excess percentage depletion		(114,000	)		(125,000	)		(207,000	)		(208,000	)
Other adjustments, net		2,000			(85,000	)		9,000			(83,000	)

Income tax expense	$	92,000		$	74,000		$	100,000		$	320,000
Effective rate expressed as a percentage
of income before income tax		15.9	%		9.2	%		11.7	%		18.7	%

The overall effective tax rate expressed as a percentage of book income before income tax for the current three month period, as compared to the same period in the prior year, was higher due to nonrecurring adjustments recorded in the three months ended September 30, 2011. These adjustments were not necessary during the three months ended September 30, 2012.

Net deferred tax assets and liabilities were comprised of:	September 30,			March 31,
	2012			2012
	(Unaudited)
Deferred tax assets:
Statutory depletion carry-forward	$	1,409,000		$	1,232,000
Asset retirement obligation		714,000			669,000
Other accruals		95,000			88,000
Allowance for doubtful accounts		22,000			22,000

Gross deferred tax assets		2,240,000			2,011,000

Deferred tax liabilities:
Depletion, depreciation and intangible drilling costs		(5,045,000	)		(4,742,000	)

Gross deferred tax liabilities		(5,045,000	)		(4,742,000	)

Deferred tax liabilities, net	$	(2,805,000	)	$	(2,731,000	)

Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, deferred taxes may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves and the depletion of these long-lived reserves.

The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions.

The Company's tax returns for the prior four tax years of filings are still subject to examination by tax authorities.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in the Company’s Annual Report on Form 10-K for the year ended March 31, 2012, as well as the unaudited condensed consolidated financial statements and related notes and other information appearing in Item 1 of this report.

The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires us to make estimates and assumptions that affect the reported amounts in the unaudited condensed consolidated financial statements and the accompanying notes including matters arising during the normal course of business. We apply our best judgment, our knowledge of existing facts and circumstances and our knowledge of actions that we may undertake in the future in determining the estimates that will affect our unaudited condensed consolidated financial statements. We evaluate our estimates on an ongoing basis using our historical experience, as well as other factors we believe appropriate under the circumstances, such as current economic conditions, and adjust or revise our estimates as circumstances change. As future events and their effects cannot be determined with precision, actual results may differ from these estimates.

As used in this report, unless the context otherwise indicates, references to “we,” “our,” 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 influenced by the prevailing prices of crude oil and natural gas. Changes in commodity prices affect, both positively and negatively, our financial condition, liquidity, ability to obtain financing and operating results. Changes in commodity prices may influence, both positively and negatively, the amount of crude oil and natural gas that we choose to produce. Prevailing prices for such commodities fluctuate in response to changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Inherently, the prices received for crude oil and natural gas production are unpredictable, and such volatility is expected. Most of our production is sold at market prices. Obviously, if the commodity indexes fluctuate, the price that we receive for our production will fluctuate. Therefore, the amount of revenue that we realize, as well as our estimates of future revenues, is to a large extent determined by factors beyond our control.

Liquidity and Capital Resources

Liquidity Outlook. Our primary source of funding is the net cash flow from the sale of our oil and natural gas production. The profitability and cash flow generated by our operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. At the current price of oil, we believe the cash generated from operations, along with existing cash balances, should enable us to meet our existing and normal recurring obligations during the next year and beyond.

Overview of our Capital Structure. We recognize the importance of developing our capital resource base in order to pursue our objectives. However, subsequent to our last public offering in 1980, debt financing has been the sole source of external funding. In addition to our routine production-related costs, general and administrative expenses and, when necessary, debt repayment requirements, we require capital to fund our exploratory and development drilling efforts and the acquisition of additional properties as well as the enhancement of held and newly acquired properties.

We have received numerous inquiries regarding the possibility of funding our efforts through equity contributions or debt instruments. Given strong cash flows, we have thus far declined these overtures. Our primary concern in this area is the dilution of our existing shareholders. However, going forward, given that one of the key components of our growth strategy is to expand our oil and natural gas reserve base through drilling and/or acquisitions, if we were presented with a significant opportunity and available cash and bank debt financing were insufficient, it is possible we would consider alternative forms of additional financing.

Hedging. During the three months ended September 30, 2012 and 2011, we did not participate in any hedging activities, nor did we have any open futures or option contracts.

Working Capital. At September 30, 2012, we had a working capital surplus of $1,824,000 (a current ratio of 1.42:1) compared to a working capital surplus at March 31, 2012 of $6,572,000 (a current ratio of 2.91:1). The decrease in current ratio is primarily a result of the use of cash for the acquisition, development and exploration of oil and gas properties.

Cash Flow. Cash provided by operating activities was $518,000 for the six months ended September 30, 2012, compared to $2,195,000 for the six months ended September 30, 2011. Changes in operating cash relate primarily to the decline in net income adjusted for non-cash expenses for the six months ended September 30, 2012 compared to the same period ended September 30, 2011. The fluctuation in deferred income tax expense, the timing and payment of accounts payable and accrued liabilities, especially pertaining to capital expenditure outlays, in addition to the timing and collection of accounts receivable and the application of prepaid balances were also factors in deriving net cash flows from operations.

Overall, net cash used in investing activities increased for the six months ended September 30, 2012, to $4,720,000, from $3,025,000 for the six months ended September 30, 2011. This was the result of an increase in the number of wells drilled and completed during the current period compared to the same period in the prior year, in addition to spending on the acquisitions of oil and gas property, as explained in “Capital Expenditures” below.

Net cash used for financing activities was $0 for the six months ended September 30, 2012 and $84,000 for the six months ended September 30, 2011 for the purchase of treasury shares.

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 condensed consolidated statements of cash flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis.

During the six months ended September 30, 2012, we spent $6,396,000 on various projects. This compares to $3,516,000 for the six months ended September 30, 2011. During the six months ended September 30, 2012, capital expenditures were comprised of the drilling and completion of six wells (approximately 0.17 net) producing as of period end (7%), the drilling of thirty-seven wells (approximately 1.27 net) to be completed as of calendar year end (87%), and leasehold expenditures (2%). The remaining costs (4%) were primarily related to recompleting existing wells. The majority (89%) of capital expenditures were spent in the Williston basin. These projects were funded entirely with internally generated cash flow and cash on hand.

We are continually evaluating drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of evaluation. Our policy is to not disclose the specifics of a project or prospect, nor to speculate on such ventures, until such time as those various opportunities are finalized and undertaken. We caution that the absence of news and/or press releases should not be interpreted as a lack of development or activity.

Divestitures/Abandonments

We neither sold nor plugged any wells during the six months ended September 30, 2012.

Impact of Inflation and Pricing

We deal primarily in U.S. dollars. Inflation has not had a material impact on the Company in recent years because of the relatively low rates of inflation in the United States. However, the oil and natural gas industry can be cyclical and the demand for production places pressure on the economic stability and pricing within the industry. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, cost declines are likely to lag and may not adjust downward in proportion to declining prices. Changes in prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel. While we do not presently expect business costs to materially rise, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Reserves

During the six months ended September 30, 2012, proved reserves in barrels of oil equivalent (“BOE”) increased 22% from March 31, 2012, from 1,335,000 to 1,625,000 at September 30, 2012. The reserve balance reflects the favorable impact of newly developed reserves offset by the natural decline curve for existing wells.

Other Commitments

We do not have any other commitments beyond our office lease and software maintenance contracts. See further detail contained in the notes to the unaudited condensed consolidated financial statements.

Results of Operations

The following provides selected financial information and averages for the three and six months ended September 30, 2012 and 2011.

	Three Months Ended September 30,				Six Months Ended September 30,
	2012		2011		2012		2011
Revenue
Oil	$	2,546,000	$	2,185,000	$	4,674,000	$	4,372,000
Gas		154,000		320,000		246,000		613,000
Total revenue 1		2,700,000		2,505,000		4,920,000		4,985,000

Total production expense 2		1,085,000		1,026,000		2,115,000		1,959,000

Gross profit	$	1,615,000	$	1,479,000	$	2,805,000	$	3,026,000

Depletion expense	$	446,000	$	217,000	$	725,000	$	402,000

Sales volume
Oil (Bbls)		31,169		25,056		58,168		47,618
Gas (Mcfs) 3		30,818		46,259		45,384		77,662

Average sales price 4
Oil (per Bbl)	$	81.68	$	87.20	$	80.35	$	91.81
Gas (per Mcf)	$	5.00	$	6.92	$	5.42	$	7.89

Average per BOE 5
Production expense 3, 4	$	29.89	$	31.31	$	32.18	$	32.35
Gross profit 4	$	44.48	$	45.14	$	42.67	$	49.97
Depletion expense 4	$	12.28	$	6.62	$	11.03	$	6.64

1		Amount does not include water service and disposal revenue. For the three and six months ended September 30, 2011, this revenue amount is net of $109,000 and $236,000, respectively, in well service and water disposal revenue, which would otherwise total $2,809,000 and $5,156,000, respectively, in revenue, compared to $40,000 and $85,000 in the respective periods ended September 30, 2011, to total $2,545,000 and $5,070,000 for the comparable three and six month periods ended September 30, 2011.
2		Overall lifting cost (oil and gas production costs, including production taxes and the cost of workovers)
3		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.
4		Averages calculated based upon non-rounded figures
5		Per equivalent barrel (6 thousand cubic feet, “Mcf”, of gas is equivalent to 1 barrel, “Bbl”, of oil)

Three months ended September 30, 2012 compared to three months ended September 30, 2011

Overview. Net income for the three months ended September 30, 2012, was $486,000 compared to net income of $728,000 for the three months ended September 30, 2011. The decrease in net income resulted from the decline in oil prices coupled with a decrease in gas sales revenue as described in “Revenues” and “Volumes and Prices” below and an increase in expenses for the current three month period.

Revenues. Oil sales revenue increased 17% for the three months ended September 30, 2012, from $2,185,000 for the three months ended September 30, 2011 compared to $2,546,000 for the current period, due to the increase in reported production, partially offset by a lower realized price per barrel as described in “Volumes and Prices” below.

Gas sales revenue decreased $166,000 (52%) for the three months ended September 30, 2012, compared to the three months ended September 30, 2011, as a result of having divested the Company’s working and/or override interests in 38 gas wells in Weld County, Colorado in January of this year.

Volumes and Prices. Oil sales volumes rose by 24% for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. The average price per barrel declined by 6% for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. The rise in oil sales volumes for the three months ended September 30, 2012 was the result of a significant contribution from 19 new producing oil wells (approximately 0.67 net) in North Dakota since the comparable period in the prior year.

The divestiture of the Company’s working and/or override interests in 38 wells in Weld County, Colorado since the comparable prior year period ended September 30, 2011, resulted in the decline in our reported natural gas production. As of September 30, 2012, we hold interests in 3 gas wells. The 28% drop in average price per Mcf for the three months ended September 30, 2012, compared to the respective period in the prior year had only a minor impact relative to the divestiture of the aforementioned properties.

Production Expense. Production expense is comprised of the following items:

	Three Months Ended September 30,
		2012		2011

Lease operating costs	$	591,000	$	551,000
Workover costs		216,000		161,000
Production taxes		262,000		200,000
Transportation and other costs		16,000		114,000

Total production expense	$	1,085,000	$	1,026,000

Oil and gas production expense increased $59,000 (6%) for the three months ended September 30, 2012, over the expenses for the three months ended September 30, 2011, primarily due to the increase in number of producing wells.

Routine lease operating expense (“LOE”), consisting of field personnel, fuel/power, chemicals, disposal and other costs, per BOE was $16.72 for the three months ended September 30, 2012, compared to $20.30 for the three months ended September 30, 2011, due primarily to the reduction in transportation costs associated with the gas properties which were divested in January of 2012.

As a percent of oil and gas sales revenue, routine LOE was 22% for the three months ended September 30, 2012, compared to 27% for the three months ended September 30, 2011. This favorable movement in cost in proportion to revenue was primarily due to the reduction in transportation costs associated with the gas properties which were divested in January of 2012.

Workover operations, which generally consist of downhole repairs on a producing well, are conducted to restore or increase production and are generally random in nature. Therefore, workovers account for unpredictable fluctuations in oil and gas expense from period to period. The number of wells on which workover costs are expended varies as does the extent of workover operations. Workover expenses increased $55,000 (34%) for the three months ended September 30, 2012, compared to the respective period ended September 30, 2011. Consequently, workover costs in the second quarter of fiscal year 2013 increased from $4.91 per BOE in the second quarter of fiscal 2012 to $5.95 per BOE in the current quarter.

Production taxes for the three months ended September 30, 2012, increased 31% over the three months ended September 30, 2011, primarily due to a reduction in production in jurisdictions with lower tax rates (Colorado and Texas) and the upsurge in production in jurisdictions with higher production tax rates (North Dakota). The increase in production volumes also contributed to the increase in production tax expense. As a percent of oil and gas sales revenue, production taxes rose to 10% from 8% for the respective prior year three month period. Production taxes are primarily based on the wellhead values of production, though normal fluctuations occur in the percentage between periods based upon the timing of approval of incentive tax credits in Texas, changes in tax rates, and changes in the proportion of our production between states. Because production tax rates vary from state to state our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those jurisdictions.

While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) increased slightly during the current quarter, those costs are spread over greater reported volumes, per BOE, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011, causing the costs per BOE to decline from $31.31 to $29.89.

Other Expenses.

Depletion and depreciation increased $232,000 (101%) for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. The increase in expense was a result of an increase in BOE production for the quarter and the addition of capital costs for newly drilled wells transferred into the pool of depletable property costs.

General & Administrative (“G&A”) expense increased $120,000 (24%) for the three months ended September 30, 2012, over the expense for the three months ended September 30, 2011. This rise in costs is comprised primarily of compensation-related expenses for additional employees, contract labor and consultants, which account for $100,000 of the increase. State franchise taxes increased $20,000 for the three month period.

The escalation in G&A costs resulted in a 12% increase in expense per BOE from $15.47 for the three months ended September 30, 2011, to $17.27 for the three months ended September 30, 2012.

Income Tax. For the three months ended September 30, 2012, we recorded income tax expense of $92,000, as compared to $74,000 for the three months ended September 30, 2011. Our effective income tax rate was 15.9% for the three months ended September 30, 2012. The overall effective tax rate expressed as a percentage of book income before income tax for the three months ended September 30, 2012, as compared to the same period in 2011, was higher due to nonrecurring adjustments in the three months ended September 30, 2011. These adjustments were not necessary during the three months ended September 30, 2012.

Six months ended September 30, 2012 compared to six months ended September 30, 2011

Overview. Net income for the six months ended September 30, 2012, was $756,000 compared to net income of $1,393,000 for the six months ended September 30, 2011. The decrease in net income resulted from the decline in oil prices coupled with a decrease in gas sales revenue as described in “Revenues” and “Volumes and Prices” below and an increase in expenses for the three month period.

Revenues. Oil sales revenue increased 7% for the six months ended September 30, 2012, from $4,372,000 for the six months ended September 30, 2011 to $4,674,000 for the current period, due to an increase in production volumes, partially offset by a lower realized price per barrel offset by the increase in reported production as described in “Volumes and Prices” below.

Gas sales revenue decreased $367,000 (60%) for the six months ended September 30, 2012, compared to the six months ended September 30, 2011, as a result of having divested the Company’s working and/or override interests in 38 gas wells in Weld County, Colorado in January of 2012.

Volumes and Prices. Oil sales volumes rose by 22% for the six months ended September 30, 2012, compared to the six months ended September 30, 2011. The average price per barrel declined by 13% for the six months ended September 30, 2012, compared to the six months ended September 30, 2011. The rise in oil sales volumes for the six months ended September 30, 2012 was the result of a significant contribution from 19 new producing oil wells (approximately 0.67 net) in North Dakota since the comparable period in the prior year.

The divestiture of the Company’s working and/or override interests in 38 wells in Weld County, Colorado since the comparable prior year period ended September 30, 2011, resulted in the decline in our reported natural gas production. As of September 30, 2012, we hold interests in 3 gas wells. The 31% drop in average price per Mcf for the six months ended September 30, 2012, compared to the respective period in the prior year had only a minor impact relative to the divestiture of the aforementioned properties.

Production Expense. Production expense is comprised of the following items:

	Six Months Ended September 30,
		2012		2011

Lease operating costs	$	1,249,000	$	1,077,000
Workover costs		387,000		361,000
Production taxes		458,000		338,000
Transportation and other costs		21,000		183,000

Total production expense	$	2,115,000	$	1,959,000

Oil and gas production expense increased $156,000 (8%) for the six months ended September 30, 2012, over the expenses for the six months ended September 30, 2011, largely due to the increase in number of producing wells.

Routine lease operating expense (“LOE”), consisting of field personnel, fuel/power, chemicals, disposal and other costs, per BOE was $19.32 for the six months ended September 30, 2012, compared to $20.81 for the six months ended September 30, 2011. Increases in lease operating costs were partially offset by reductions in transportation costs and total production expense in the six months ended September 30, 2012 and was allocated over a larger production volume than in the six months ended September 30, 2011.

As a percent of oil and gas sales revenue, routine LOE was 26% for the six months ended September 30, 2012 and 25% for the six months ended September 30, 2011.

Workover operations, which generally consist of downhole repairs on a producing well, are conducted to restore or increase production and are generally random in nature. Therefore, workovers account for unpredictable fluctuations in oil and gas expense from period to period. The number of wells on which workover costs are expended varies as does the extent of workover operations. Workover expenses increased $26,000 (7%) for the six months ended September 30, 2012, compared to the respective period ended September 30, 2011. While workover costs increased, the costs were spread over increased production volumes resulting in a decrease in workover costs per BOE in the six months ended September 30, 2012 to $5.89 from $5.96 per BOE in the six months ended September 30, 2011.

Production taxes for the six months ended September 30, 2012, increased 36% over the six months ended September 30, 2011, primarily due to a reduction in production in jurisdictions with lower tax rates (Colorado and Texas) and the upsurge in production in jurisdictions with higher production tax rates (North Dakota). The increase in production volumes also contributed to the increase in production tax expense. As a percent of oil and gas sales revenue, production taxes rose to 9% from 7% for the respective prior year six month period. Production taxes are primarily based on the wellhead values of production, though normal fluctuations occur in the percentage between periods based upon the timing of approval of incentive tax credits in Texas, changes in tax rates, and changes in the proportion of our production between states. Because production tax rates vary from state to state our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those jurisdictions.

While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) increased slightly during the current period, those costs are spread over greater reported volumes per BOE, for the six months ended September 30, 2012, compared to the six months ended September 30, 2011, causing the cost per BOE to decline from $32.35 to $32.18.

Other Expenses.

Depletion and depreciation increased $330,000 (78%) for the six months ended September 30, 2012, compared to the six months ended September 30, 2011. The increase in expense was a result of an increase in BOE production for the quarter and the addition of capital costs for newly drilled wells into the pool of depletable property costs.

General & Administrative (“G&A”) expense increased $359,000 (38%) for the six months ended September 30, 2012, over the expense for the six months ended September 30, 2011. This rise in costs is comprised primarily of compensation-related expenses for additional employees, contact labor and consultants, which account for $291,000 of the increase. Public company expenses and state franchise taxes were up $15,000 and $40,000, respectively, for the six month period.

The escalation in G&A costs resulted in the 27% increase in expense per BOE from $15.67 for the six months ended September 30, 2011, to $19.90 for the six months ended September 30, 2012.

Income Tax. For the six months ended September 30, 2012, we recorded income tax expense of $100,000, as compared to $320,000 for the six months ended September 30, 2011. Our effective income tax rate was 12.1% for the six months ended September 30, 2012. The overall effective tax rate expressed as a percentage of book income before income tax for the six months ended September 30, 2012, as compared to the same period in 2011, was lower due primarily to lower pre-tax income and increased capital expenditures compared to the comparable period.

Off Balance Sheet Arrangements

We have no significant off balance sheet transactions, arrangements or obligations.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the phrase “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2012. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Interim Chief Financial Officer concluded that, as of September 30, 2012, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

Not applicable.

Purchases of Equity Securities

The following summarizes monthly share repurchase activity for the second quarter of the year ending March 31, 2013:

	Total Number of Shares Purchased¹		Average Price Paid Per Share		Number of Shares Purchased as Part of a Publicly Announced Plan¹		Maximum Shares that May Yet be Purchased under the Plan¹
July 1, 2012 – July 31, 2012		—	$	—		—		103,284
August 1, 2012 – August 31, 2012		—	$	—		—		103,284
September 1, 2012 – September 30, 2012		—	$	—		—		103,284
Total		—				—

On October 22, 2008, the Company’s Board of Directors authorized a share buyback program for the Company to repurchase up to 50,000 pre-split shares of its common stock for a period of up to 18 months. The program does not require the Company to repurchase any specific number of shares, and the Company may terminate the repurchase program at any time. On November 13, 2009, the Board of Directors increased the number of shares authorized for repurchase to 150,000 pre-split shares. On February 10, 2010, the Board extended the termination date of the program from April 22, 2010 to October 22, 2011. On November 7, 2011, the Board further extended the termination date of the program from October 22, 2011 to October 22, 2013. During the quarter ended September 30, 2012, no shares were repurchased under the share buyback program and 103,284 shares (11,067 post-split shares) remain available for future repurchase.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

Exhibit No.		Document

31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer).

31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial Officer).

32.1		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer).

32.2		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial Officer).

101		The following materials from the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 2012, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Statements of Operations, (ii) the Unaudited Condensed Consolidated Balance Sheets, (iii) the Unaudited Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Unaudited Condensed Consolidated Financial Statements, tagged as blocks of text.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed by the following authorized persons on behalf of Earthstone Energy, Inc.

	EARTHSTONE ENERGY, INC.

Date: November 13, 2012	By:	/s/ Ray Singleton
		Ray Singleton
		President and Chief Executive Officer


	By:	/s/ Jim Poage
		Jim Poage
		Interim Chief Financial Officer