Earthstone Energy (ESTE) 10-Q 2013 Q3 Quarterly report

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 December 31, 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 February 8, 2013: 1,720,712

EARTHSTONE ENERGY, INC.

FORM 10-Q

INDEX

PART I.   FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements		4
	Condensed Consolidated Balance Sheets:
	December 31, 2012 (Unaudited) and March 31, 2012		4
	Condensed Consolidated Statements of Operations:
	Three Months and Nine Months Ended December 31, 2012 and 2011(Unaudited)		6
	Condensed Consolidated Statements of Cash Flows:
	Nine Months Ended December 31, 2012 and 2011 (Unaudited)		7
	Notes to Unaudited Condensed Consolidated Financial Statements:
	December 31, 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		22
Item 4.	Mine Safety Disclosures		22
Item 5.	Other Information		22
Item 6.	Exhibits		22
Signatures			23

2

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;

●   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 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.

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PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

Page 1 of 2

	December 31,			March 31,
	2012			2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,157,000		$	6,778,000
Accounts receivable:
Oil and gas sales		2,988,000			2,389,000
Joint interest and other receivables
net of allowance of ($38,000) and ($60,000), respectively		195,000			90,000
Other current assets		785,000			749,000
Total current assets		6,125,000			10,006,000
Oil and gas properties, full cost method:
Proved properties		48,166,000			37,112,000
Unproved properties		2,908,000			4,409,000
Accumulated depletion and impairment		(27,062,000	)		(25,778,000	)
Net oil and gas properties		24,012,000			15,743,000
Support equipment and other non-current assets
net of accumulated depreciation of ($402,000) and ($383,000), respectively		529,000			457,000
Total non-current assets		24,541,000			16,200,000
Total assets	$	30,666,000		$	26,206,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

Page 2 of 2

	December 31,			March 31,
	2012			2012
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,280,000		$	824,000
Accrued liabilities		3,199,000			2,610,000
Total current liabilities		4,479,000			3,434,000
Long-term liabilities:
Long term debt		2,000,000			-
Deferred tax liability		2,892,000			2,731,000
Asset retirement obligation, less current portion		1,688,000			1,693,000
Total long-term liabilities		6,580,000			4,424,000
Total liabilities		11,059,000			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		18,000			18,000
1,802,000 and 1,788,000 shares issued, respectively
Additional paid-in capital		23,241,000			23,108,000
Treasury stock, at cost, 82,000 shares		(457,000	)		(457,000	)
Accumulated deficit		(3,195,000	)		(4,321,000	)
Total shareholders’ equity		19,607,000			18,348,000
Total liabilities and shareholders’ equity	$	30,666,000		$	26,206,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

5

Earthstone Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended					Nine Months Ended
	December 31,					December 31,
	2012			2011		2012			2011
Revenues:
Oil and gas sales	$	2,752,000		$	3,830,000	$	7,672,000		$	8,815,000
Well service and water-disposal revenue		82,000			36,000		318,000			121,000
Total revenues		2,834,000			3,866,000		7,990,000			8,936,000
Expenses:
Oil and gas production		866,000			983,000		2,523,000			2,610,000
Production tax		239,000			350,000		697,000			688,000
Well service and water-disposal		18,000			-		60,000			-
Depletion and depreciation		577,000			363,000		1,332,000			788,000
Accretion of asset retirement obligation		43,000			43,000		130,000			125,000
General and administrative		669,000			473,000		1,977,000			1,422,000
Total expenses		2,412,000			2,212,000		6,719,000			5,633,000
Income from operations		422,000			1,654,000		1,271,000			3,303,000
Other income (expense):
Interest and other income		51,000			1,000		59,000			68,000
Interest and other expenses		(2,000	)		-		(3,000	)		(3,000	)
Total other income		49,000			1,000		56,000			65,000
Income before income tax		471,000			1,655,000		1,327,000			3,368,000
Current income tax expense		14,000			34,000		40,000			129,000
Deferred income taxexpense		87,000			469,000		161,000			694,000
Total income tax expense		101,000			503,000		201,000			823,000
Net income	$	370,000		$	1,152,000	$	1,126,000		$	2,545,000
Per share amounts:
Basic	$	0.22		$	0.68	$	0.65		$	1.49
Diluted	$	0.22		$	0.68	$	0.65		$	1.49
Weighted average common shares outstanding:
Basic		1,720,712			1,706,588		1,720,712			1,710,035
Diluted		1,720,712			1,706,588		1,720,712			1,710,035

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

6

Earthstone Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	December 31,
	2012			2011
Cash flows from operating activities:
Net income	$	1,126,000		$	2,545,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and depreciation		1,332,000			788,000
Deferred income tax expense		161,000			694,000
Accretion of asset retirement obligation		130,000			125,000
Share-based compensation		133,000			66,000
Change in:
Accounts receivable, net		(704,000	)		(938,000	)
Other current assets		(148,000	)		62,000
Accounts payable, accrued and other liabilities		(48,000	)		(258,000	)
Net cash provided by operating activities		1,982,000			3,084,000
Cash flows from investing activities:
Oil and gas properties		(8,483,000	)		(4,663,000	)
Purchases of support equipment and other non-current assets		(90,000	)		(96,000	)
Net cash (used in) investing activities		(8,573,000	)		(4,759,000	)
Cash flows from financing activities:
Borrowings on long term debt		2,000,000			-
Deferred financing fees		(30,000	)		-
Purchase of treasury shares		-			(84,000	)
Net cash provided by (used in) financing activities		1,970,000			(84,000	)
Cash and cash equivalents:
Net decrease in cash and cash equivalents		(4,621,000	)		(1,759,000	)
Cash and cash equivalents, beginning of year		6,778,000			4,051,000
Cash and cash equivalents, end of period	$	2,157,000		$	2,292,000
Supplemental disclosure of cash flow information:
Cash paid for interest	$	3,000		$	-
Cash paid for income tax	$	341,000		$	1,000
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	35,000		$	10,000
Accrued capital expenditures	$	923,000		$	957,000
Prepaid capital expenditures	$	112,000		$	46,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

7

Earthstone Energy, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 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 nine 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

	12/31/12		03/31/12
	(Unaudited)
Drilling and completion cost prepayments	$	264,000	$	230,000
Lease and well equipment inventory		323,000		412,000
Prepaid insurance premiums		33,000		73,000
Prepaid income tax		132,000		-
Other current assets		33,000		34,000
Total other current assets	$	785,000	$	749,000

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3. Accrued Liabilities

	12/31/12		03/31/12
	(Unaudited)
Accrued operations payable	$	2,176,000	$	1,472,000
Accrued compensation		341,000		445,000
Accrued income tax payable and other		263,000		393,000
Revenue and production taxes payable		116,000		167,000
Short term asset retirement obligation		303,000		133,000
Total accrued liabilities	$	3,199,000	$	2,610,000

4. Oil and Gas Properties

	12/31/12			03/31/12
	(Unaudited)
Proved properties	$	48,166,000		$	37,112,000
Unproved properties		2,908,000			4,409,000
Less accumulated depletion and impairment		(27,062,000	)		(25,778,000	)
Total accrued liabilities	$	24,012,000		$	15,743,000

As of December 31, 2012, the Company has recorded $48,166,000 as proved property costs. As of March 31, 2012, the Company had recorded $37,112,000 as proved property costs. Additions of $11,054,000 recorded during the nine months ended December 31, 2012 include $9,372,000 primarily related to intangible drilling costs and tangible completion costs in North Dakota. In addition, $1,682,000 in costs were transferred from unproved to proved properties.

As of December 31, 2012, the Company has recorded $2,908,000 as unproved property costs. As of March 31, 2012, the Company had recorded $4,409,000 as unproved property costs. As of December 31, 2012, the Company recorded additional unproved property costs of $181,000 and transferred $1,682,000 in costs from unproved to proved properties.

5. Long Term Debt

On December 21, 2012, the Company entered into a $25 million senior secured revolving bank credit facility (the "Credit Facility") the Bank of Oklahoma (the "Bank"). The initial borrowing base on the Credit Facility is $6 million. The maturity date of the Credit Facility is December 21, 2017. The Credit Facility is secured by mortgages on certain Company 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.

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. As of December 31, 2012, the Company is in compliance with all of the financial covenants under the Credit Facility.

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. These costs have been recorded as deferred financing costs and will be amortized over the term of the note. Additional borrowing base fees may be payable upon future increases in the borrowing base, if any. As of December 31, 2012, the Company had an outstanding balance under the Credit Facility of $2 million.

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6. Income Tax

The provision for income tax is comprised of:

	Three Months Ended December 31,				Nine Months Ended December 31,
	2012		2011		2012		2011
	(Unaudited)		(Unaudited)		(Unaudited)		(Unaudited)
Current:
Federal	$	13,000	$	29,000	$	36,000	$	114,000
State		1,000		5,000		4,000		15,000
Total current income tax		14,000		34,000		40,000		129,000
Deferred:
Federal		80,000		438,000		149,000		648,000
State		7,000		31,000		12,000		46,000
Total deferred income tax		87,000		469,000		161,000		694,000
Income tax expense	$	101,000	$	503,000	$	201,000	$	823,000

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

	Three Months Ended December 31,						Nine Months Ended December 31,
	2012			2011			2012			2011
	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
Federal tax at statutory rate	$	160,000		$	562,000		$	451,000		$	1,145,000
State taxes, net of federal benefit		5,000			27,000			12,000			55,000
Excess percentage depletion		(89,000	)		(163,000	)		(296,000	)		(371,000	)
Other adjustments, net		25,000			77,000			34,000			(6,000	)
Income tax expense	$	101,000		$	503,000		$	201,000		$	823,000
Effective rate expressed as a percentage
of income before income tax		21.4	%		30.4	%		15.2	%		24.4	%

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 lower due to nonrecurring adjustments recorded in the three months ended December 31, 2011. These adjustments were not necessary during the three months ended December 31, 2012.

10

Net deferred tax assets and liabilities were comprised of:

	December 31,			March 31,
	2012			2012
	(Unaudited)
Deferred tax assets:
Statutory depletion carry-forward	$	1,367,000		$	1,232,000
Asset retirement obligation		730,000			669,000
Other accruals		103,000			88,000
Allowance for doubtful accounts		14,000			22,000
Gross deferred tax assets		2,214,000			2,011,000
Deferred tax liabilities:
Depletion, depreciation and intangible drilling costs		(5,106,000	)		(4,742,000	)
Gross deferred tax liabilities		(5,106,000	)		(4,742,000	)
Deferred tax liabilities, net	$	(2,892,000	)	$	(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.

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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 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 which is intended to provide an additional source of funds to pay our share of drilling and completion costs incurred on wells drilled and completed in the Williston Basin. The initial borrowing base on the Credit Facility is $6 million and, as of December 31, 2012, we had an outstanding balance of $2 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. As of December 31, 2012, we were in compliance with all of the financial covenants under the Credit Facility. Our ability to remain in compliance with the financial covenants 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. For further information concerning the Credit Facility and its terms, see our Form 8-K filed with the SEC on January 3, 2013 and footnote 5 to our unaudited financials set forth herein.

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Overviewof 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.  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 December 31, 2012 and 2011, we did not participate in any hedging activities, nor did we have any open futures or option contracts. 

Working Capital. At December 31, 2012, we had a working capital surplus of $1,646,000 (a current ratio of 1.37:1) 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 development and exploration of oil and gas properties coupled with a decrease in cash provided by operations as discussed further below.

Cash Flow. Cash provided by operating activities was $1,982,000 for the nine months ended December 31, 2012, compared to $3,084,000 for the nine months ended December 31, 2011. Changes in operating cash relate primarily to the decline in net income adjusted for non-cash expenses for the nine months ended December 31, 2012 compared to the same period ended December 31, 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 nine months ended December 31, 2012, to $8,573,000 from $4,759,000 for the nine months ended December 31, 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 provided by financing activities was $1,970,000 for the nine months ended December 31, 2012 related to $2 million in borrowing on a bank credit facility net of related financing fees of $30,000 paid in cash.  Net cash used in financing activities was $84,000 for the nine months ended December 31, 2011 related to 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.

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During the nine months ended December 31, 2012, we spent $9,553,000 on various projects.  This compares to $5,427,000 for the nine months ended December 31, 2011.  During the nine months ended December 31, 2012, capital expenditures were comprised of the drilling and completion of wells producing as of period end ($5,141,000 or 54%), the drilling of wells to be completed as of fiscal year end ($3,811,000 or 40%), and leasehold expenditures ($304,000 or 3%).  The remaining costs ($297,000 or 3%) were primarily related to recompleting existing wells and miscellaneous costs.  These costs were funded primarily 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 nine months ended December 31, 2012.

Impact of Inflation and Pricing

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 nine months ended December 31, 2012, proved reserves in barrels of oil equivalent (“BOE”) increased 42% from 1,335,000 at March 31, 2012 to 1,895,000 at December 31, 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.

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Results of Operations

The following provides selected financial information and averages for the three and nine months ended December 31, 2012 and 2011.

		Three Months Ended December 31,				Nine Months Ended December 31,
		2012		2011		2012		2011
Revenue
Oil	$	2,589,000	$	3,409,000	$	7,263,000	$	7,781,000
Gas		163,000		421,000		409,000		1,034,000
Total revenue1		2,752,000		3,830,000		7,672,000		8,815,000
Total production expense 2		1,105,000		1,333,000		3,220,000		3,292,000
Gross profit	$	1,647,000	$	2,497,000	$	4,452,000	$	5,523,000
Depletion expense	$	559,000	$	350,000	$	1,284,000	$	752,000
Sales volume
Oil (Bbls)		31,549		38,809		89,717		86,427
Gas (Mcfs) 3		26,542		63,281		71,926		140,943
Average sales price 4
Oil (per Bbl)	$	82.06	$	87.84	$	80.95	$	90.03
Gas (per Mcf)	$	6.14	$	6.65	$	5.69	$	7.34
Average per BOE 5
Production expense 3, 4	$	30.72	$	27.01	$	31.66	$	29.95
Gross profit 4	$	45.78	$	50.59	$	43.77	$	50.25
Depletion expense 4	$	15.54	$	7.09	$	12.62	$	6.84

1	Amount does not include water service and disposal revenue.  For the three and nine months ended December 31, 2012, this revenue amount is net of $82,000 and $318,000, respectively, in well service and water disposal revenue, which would otherwise total $2,834,000 and $7,990,000, respectively, in revenue, compared to $36,000 and $121,000 in the respective periods ended December 31, 2011, to total $3,866,000 and $8,936,000 for the comparable three and nine month periods ended December 31, 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)

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Three months ended December 31, 2012 compared to three months ended December 31, 2011

Overview. Net income for the three months ended December 31, 2012, was $370,000 compared to net income of $1,152,000 for the three months ended December 31, 2011. The decrease in net income resulted from the decline in oil volumes and 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 decreased $820,000 (24%) for the three months ended December 31, 2012 to $2,589,000 from $3,409,000 for the three months ended December 31, 2011, due to the decrease in reported production and a lower realized price per barrel as described in “Volumes and Prices” below.

Gas sales revenue decreased $258,000 (61%) for the three months ended December 31, 2012, compared to the three months ended December 31, 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 declined by 19% for the three months ended December 31, 2012, compared to the three months ended December 31, 2011. In addition, the average price per barrel declined by 7% for the three months ended December 31, 2012, compared to the three months ended December 31, 2011. The decline in oil sales volumes for the three months ended December 31, 2012 when compared to the three months ended December 31, 2011 was primarily the result of the recording of significant amounts of true-ups from prior quarters at December 31, 2011. These true-ups, totaling 4,918 barrels of oil, resulted in the volumes reported for the three months ended December 31, 2011 being higher than the normal volumes that would have been reported for the quarter, thereby resulting in the apparent decline in volumes reported when comparing the three months ended December 31, 2012 to the three months ended December 31, 2011.

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 December 31, 2011, resulted in the decline in our reported natural gas production.  As of December 31, 2012, we hold interests in 3 gas wells.  The 8% drop in average price per Mcf for the three months ended December 31, 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 December 31,
		2012		2011
Lease operating costs	$	654,000	$	601,000
Workover costs		186,000		304,000
Production taxes		239,000		350,000
Transportation and other costs		26,000		78,000
Total production expense	$	1,105,000	$	1,333,000

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Oil and gas production expense decreased $228,000 (17%) for the three months ended December 31, 2012, as compared to the expenses for the three months ended December 31, 2011, primarily due to a decrease in workover costs and a reduction in production tax expense related to the reduced production volume.

Routine lease operating expense (“LOE”), consisting of field personnel, fuel/power, chemicals, disposal and other costs, per BOE was $18.90 for the three months ended December 31, 2012, compared to $13.76 for the three months ended December 31, 2011.  While the total dollars spent on routine lease operating expense was virtually the same for each of these periods, the costs are being divided over fewer BOE in the three months ended December 31, 2012 resulting in a higher cost per BOE.

As a percent of oil and gas sales revenue, routine LOE was 25% for the three months ended December 31, 2012, compared to 18% for the three months ended December 31, 2011.  This increase in cost in proportion to revenue was due to a combination of the decrease in production volume, the increase in the number of producing wells and increasing LOE costs on previously producing horizontal Bakken wells.

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 decreased $118,000 (39%) for the three months ended December 31, 2012, compared to the respective period ended December 31, 2011.  Consequently, workover costs in the third quarter of fiscal year 2013 decreased to $5.17 per BOE from $6.16 per BOE in the third quarter of fiscal 2012.

Production taxes for the three months ended December 31, 2012, decreased 32% over the three months ended December 31, 2011.  As a percent of oil and gas sales revenue, production taxes remained the same between the two periods at 9%.  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) decreased during the current quarter, those costs are spread over smaller reported volumes, per BOE, for the three months ended December 31, 2012, compared to the three months ended December 31, 2011, causing the costs per BOE to increase from $27.01 to $30.72.

Other Expenses.

Depletion and depreciation increased $214,000 (59%) for the three months ended December 31, 2012, compared to the three months ended December 31, 2011.  The increase in expense was a result of the addition of capital costs for newly drilled wells transferred into the pool of depletable property costs offset partially by an increase in total reserves and the smaller volume of BOE production during the current quarter.

General and Administrative (“G&A”) expense increased $196,000 (41%) for the three months ended December 31, 2012, over the expense for the three months ended December 31, 2011.  This rise in costs is comprised primarily of compensation-related expenses for additional employees, contract labor and consultants.

The escalation in G&A costs resulted in a 94% increase in expense per BOE from $9.58 for the three months ended December 31, 2011, to $18.60 for the three months ended December 31, 2012.

Income Tax.  For the three months ended December 31, 2012, we recorded income tax expense of $101,000, as compared to $503,000 for the three months ended December 31, 2011.  Our effective income tax rate was 21.4% for the three months ended December 31, 2012.  The overall effective tax rate expressed as a percentage of book income before income tax for the three months ended December 31, 2012, as compared to the same period in 2011, was lower due to nonrecurring adjustments in the three months ended December 31, 2011.  These adjustments were not necessary during the three months ended December 31, 2012.  

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Nine months ended December 31, 2012 compared to nine  months ended December 31, 2011

Overview.  Net income for the nine months ended December 31, 2012, was $1,126,000 compared to net income of $2,545,000 for the nine months ended December 31, 2011.  The decrease in net income resulted from the decline in oil prices and volumes 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 declined $518,000 (7%) for the nine months ended December 31, 2012, from $7,781,000 for the nine months ended December 31, 2011 to $7,263,000 for the current period, due to a 10% lower realized price per barrel, partially offset by a 4% increase in production volume as described in “Volumes and Prices” below.

Gas sales revenue decreased $625,000 (60%) for the nine months ended December 31, 2012, compared to the nine months ended December 31, 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 4% for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011.  The average price per barrel declined by 10% for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011.  The rise in oil sales volumes for the nine months ended December 31, 2012 was the result of the net contribution from newly producing horizontal Bakken wells in North Dakota drilled this year versus steep declines in production on previously producing horizontal Bakken wells 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 December 31, 2011, resulted in the decline in our reported natural gas production.  As of December 31, 2012, we hold interests in 3 gas wells.  The 22% drop in average price per Mcf for the nine months ended December 31, 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:

	Nine Months Ended December 31,
		2012		2011
Lease operating costs	$	1,903,000	$	1,678,000
Workover costs		573,000		665,000
Production taxes		697,000		688,000
Transportation and other costs		47,000		261,000
Total production expense	$	3,220,000	$	3,292,000

Oil and gas production expense decreased $72,000 (2%) for the nine months ended December 31, 2012, over the expenses for the nine months ended December 31, 2011, largely due to the reduction in transportation costs (associated with divested Colorado properties) and a reduction in workover costs, partially offset by increases in lease operating costs due to the increase in the number of producing wells.

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Routine lease operating expense (“LOE”), consisting of field personnel, fuel/power, chemicals, disposal and other costs, per BOE was $19.17 for the nine months ended December 31, 2012, compared to $17.64 for the nine months ended December 31, 2011.  Increases in lease operating costs were partially offset by reductions in transportation costs and total production expense in the nine months ended December 31, 2012. The slight increase in routine lease operating expense was allocated over a smaller production volume than in the nine months ended December 31, 2011 resulting in the increase in cost per BOE.

As a percent of oil and gas sales revenue, routine LOE was 25% for the nine months ended December 31, 2012 and 22% for the nine months ended December 31, 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 decreased $92,000 (14%) for the nine months ended December 31, 2012, compared to the respective period ended December 31, 2011 resulting in a decrease in workover costs per BOE in the nine months ended December 31, 2012 to $5.63 from $6.05 per BOE in the nine months ended December 31, 2011.

Production taxes for the nine months ended December 31, 2012, increased 1% over the nine months ended December 31, 2011. As a percent of oil and gas sales revenue, production taxes rose from 8% to 9% for the respective prior year nine month period. 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) decreased slightly during the current period, those costs are spread over smaller reported volumes per BOE, for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011, causing the cost per BOE to increase from $29.95 to $31.66.

Other Expenses.

Depletion and depreciation increased $544,000 (69%) for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011. The increase in expense was a result of the addition of capital costs for newly drilled wells transferred into the pool of depletable property costs offset partially by an increase in total reserves and the smaller volume of BOE production during the current nine months.

General and Administrative expense increased $555,000 (39%) for the nine months ended December 31, 2012, over the expense for the nine months ended December 31, 2011. This rise in costs is comprised primarily of compensation-related expenses for additional employees, contact labor and consultants, which account for $492,000 of the increase. Public company expenses and state franchise taxes were up $39,000 and $35,000, respectively, for the nine month period.

The escalation in G&A costs resulted in the 50% increase in expense per BOE from $12.94 for the nine months ended December 31, 2011, to $19.44 for the nine months ended December 31, 2012.

Income Tax. For the nine months ended December 31, 2012, we recorded income tax expense of $201,000, as compared to $823,000 for the nine months ended December 31, 2011. Our effective income tax rate was 15.2% for the nine months ended December 31, 2012. The overall effective tax rate expressed as a percentage of book income before income tax for the nine months ended December 31, 2012, as compared to the same period in 2011, was lower due primarily to lower pre-tax income and increased capital expenditures in the current period compared to the same period in the prior year.

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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 December 31, 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 December 31, 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.

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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 third quarter of the fiscal 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
October 1, 2012 – October 31, 2012		-	$	-		-		103,284
November 1, 2012 – November 30, 2012		-	$	-		-		103,284
December 1, 2012 – December 31, 2012		-	$	-		-		103,284
Total		-				-

¹ On October 22, 2008, the Company’s Board of Directors authorized a share buyback program for the Company to repurchase up to 50,000 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 December 31, 2012, no shares were repurchased under the share buyback program and 103,284 shares (11,067 post-split shares) remain available for future repurchase.

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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 (Paul D. Maniscalco, 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 (Paul D. Maniscalco, Interim Chief Financial Officer).
101	The following materials from the Company’s quarterly report on Form 10-Q for the quarter ended December 31, 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.

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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: February 8, 2013	By:	/s/ Ray Singleton
		Ray Singleton
		President and Chief Executive Officer
	By:	/s/ Paul D. Maniscalco
		Paul D. Maniscalco
		Interim Chief Financial Officer

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