EARTHSTONE ENERGY INC - Quarter Report: 2013 December (Form 10-Q)

este_10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended December 31, 2013

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

(State of Incorporation or Organization)

84-0592823

(I.R.S. Employer Identification No.)

633 17th Street, Suite 2320, Denver, Colorado

(Address of principal executive office)

80202-3619

(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 Smaller reporting company þ

(Do not check if a smaller reporting company)

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 13, 2014: 1,732,220

EARTHSTONE ENERGY, INC.

FORM 10-Q

INDEX

	PART I. FINANCIAL INFORMATION	Page

Item 1.	Financial Statements

	Condensed Consolidated Balance Sheets:
	December 31, 2013 (Unaudited) and March 31, 2013	4

	Condensed Consolidated Statements of Operations:
	Three Months and Nine Months Ended December 31, 2013 and 2012 (Unaudited)	6

	Condensed Consolidated Statements of Cash Flows:
	Nine Months Ended December 31, 2013 and 2012 (Unaudited)	7

	Notes to Unaudited Condensed Consolidated Financial Statements:
	December 31, 2013	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, sales 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.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

Page 1 of 2

	December 31,			March 31,
	2013			2013
	(Unaudited)

ASSETS
Current assets:
Cash and cash equivalents	$	2,073,000		$	2,180,000
Accounts receivable:
Oil and gas sales		3,201,000			3,055,000
Joint interest and other receivables
net of allowance of ($41,000) and ($38,000), respectively		153,000			328,000
Other current assets		1,207,000			814,000

Total current assets		6,634,000			6,377,000

Oil and gas properties, full cost method:
Proved properties		66,154,000			53,265,000
Unproved properties		1,145,000			2,156,000
Accumulated depletion and impairment		(30,447,000	)		(27,729,000	)

Net oil and gas properties		36,852,000			27,692,000

Support equipment and other non-current assets
net of accumulated depreciation of ($500,000) and ($416,000), respectively		804,000			611,000

Total non-current assets		37,656,000			28,303,000

Total assets	$	44,290,000		$	34,680,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

Page 2 of 2

	December 31,			March 31,
	2013			2013
	(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	340,000		$	1,631,000
Accrued liabilities		6,839,000			3,971,000

Total current liabilities		7,179,000			5,602,000

Long-term liabilities:
Long-term debt		8,000,000			4,000,000
Deferred tax liability		3,798,000			2,971,000
Asset retirement obligation, less current portion		2,025,000			1,809,000

Total long-term liabilities		13,823,000			8,780,000

Total liabilities		21,002,000			14,382,000

Shareholders’ equity:
Preferred shares, $0.001 par value, 600,000 authorized		-			-
and none issued or outstanding
Common shares, $0.001 par value, 6,400,000 shares authorized and		18,000			18,000
1,768,000 and 1,802,000 shares issued, respectively
Additional paid-in capital		23,419,000			23,278,000
Treasury stock, at cost, 36,000 and 82,000 shares, respectively		(458,000	)		(457,000	)
Accumulated earnings (deficit)		309,000			(2,541,000	)

Total shareholders’ equity		23,288,000			20,298,000

Total liabilities and shareholders’ equity	$	44,290,000		$	34,680,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
Revenues:
Oil and gas sales	$	4,490,000		$	2,752,000		$	12,699,000		$	7,672,000
Well service and water-disposal revenue		(16,000	)		82,000			42,000			318,000

Total revenues		4,474,000			2,834,000			12,741,000			7,990,000

Expenses:
Oil and gas production		1,045,000			866,000			2,748,000			2,523,000
Production tax		468,000			239,000			1,208,000			697,000
Well service and water-disposal		18,000			18,000			74,000			60,000
Depletion and depreciation		1,036,000			577,000			2,802,000			1,332,000
Accretion of asset retirement obligation		52,000			43,000			150,000			130,000
General and administrative		628,000			669,000			1,980,000			1,977,000

Total expenses		3,247,000			2,412,000			8,962,000			6,719,000

Income from operations		1,227,000			422,000			3,779,000			1,271,000

Other income (expense):
Interest and other income		50,000			51,000			65,000			59,000
Interest and other expenses		(48,000	)		(2,000	)		(125,000	)		(3,000	)

Total other income (expense)		2,000			49,000			(60,000	)		56,000

Income before income tax		1,229,000			471,000			3,719,000			1,327,000

Current income tax (benefit) expense		(28,000	)		14,000			42,000			40,000
Deferred income tax expense		324,000			87,000			827,000			161,000

Total income tax expense		296,000			101,000			869,000			201,000

Net income	$	933,000		$	370,000		$	2,850,000		$	1,126,000

Per share amounts:
Basic	$	0.54		$	0.22		$	1.65		$	0.65
Diluted	$	0.54		$	0.22		$	1.65		$	0.65

Weighted average common shares outstanding:
Basic		1,732,230			1,720,712			1,732,243			1,720,712
Diluted		1,732,230			1,720,712			1,732,243			1,720,712

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	December 31,
	2013			2012
Cash flows from operating activities:
Net income	$	2,850,000		$	1,126,000
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion and depreciation		2,802,000			1,332,000
Deferred income tax expense		827,000			161,000
Accretion of asset retirement obligation		150,000			130,000
Share-based compensation		141,000			133,000
Amortization of deferred financing costs		9,000			―
Change in:
Accounts receivable, net		29,000			(704,000	)
Other current assets		(406,000	)		(148,000	)
Accounts payable, accrued and other liabilities		(1,337,000	)		(48,000	)

Net cash provided by operating activities		5,065,000			1,982,000

Cash flows from investing activities:
Oil and gas properties		(9,177,000	)		(8,483,000	)
Purchases of support equipment and other non-current assets		(164,000	)		(90,000	)
Proceeds from sale of oil and gas property and equipment		291,000			―
Other		(75,000	)		―

Net cash used in investing activities		(9,125,000	)		(8,573,000	)

Cash flows from financing activities:
Borrowings on long-term debt		4,000,000			2,000,000
Deferred financing fees		(46,000	)		(30,000	)
Purchase of treasury shares		(1,000	)		―

Net cash provided by financing activities		3,953,000			1,970,000

Cash and cash equivalents:
Net decrease in cash and cash equivalents		(107,000	)		(4,621,000	)
Cash and cash equivalents, beginning of year		2,180,000			6,778,000

Cash and cash equivalents, end of period	$	2,073,000		$	2,157,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	115,000		$	3,000
Cash paid for income tax	$	1,000		$	341,000
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	77,000		$	35,000
Accrued capital expenditures	$	2,903,000		$	923,000
Prepaid capital expenditures	$	13,000		$	112,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2013

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 and nine months covered by this report, are not necessarily indicative of the operating results that may be expected for the full fiscal 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. The carrying value of the Company's Credit Facility approximates its fair value, interest rates are variable based on prevailing market rates.

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. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company was required to implement this guidance effective for the first quarter of fiscal 2014. The adoption of ASU 2011-11 did not have a material impact on its consolidated financial statements.

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

2. Other Current Assets

	12/31/13		03/31/13
	(Unaudited)
Drilling and completion cost prepayments		693,000	$	371,000
Lease and well equipment inventory		371,000		210,000
Prepaid income tax		70,000		112,000
Prepaid insurance premiums		38,000		88,000
Other current assets		35,000		33,000

Total other current assets	$	1,207,000	$	814,000

3. Accrued Liabilities

	12/31/13		03/31/13
	(Unaudited)
Accrued operations payable	$	5,806,000	$	2,933,000
Accrued compensation		328,000		429,000
Short-term asset retirement obligation		306,000		296,000
Accrued income tax payable and other		242,000		213,000
Revenue and production taxes payable		157,000		100,000

Total accrued liabilities	$	6,839,000	$	3,971,000

4. Oil and Gas Properties

	12/31/13			03/31/13
	(Unaudited)
Proved properties	$	66,154,000		$	53,265,000
Unproved properties		1,145,000			2,156,000
Less accumulated depletion and impairment		(30,447,000	)		(27,729,000	)

Total oil and gas properties	$	36,852,000		$	27,692,000

As of December 31, 2013, the Company has recorded $66,154,000 as proved property costs. As of March 31, 2013, the Company had recorded $53,265,000 as proved property costs. Additions of $12,170,000 have been recorded during the nine months ended December 31, 2013, included in these additions are $12,000,000 related to intangible drilling and completion costs and tangible drilling and completion costs. Of the total additions recorded during the nine months ended December 31, 2013, 92% relate to our work in North Dakota.

As of December 31, 2013, the Company has recorded $1,145,000 as unproved property costs. As of March 31, 2013, the Company had recorded $2,156,000 as unproved property costs. For the nine months ended December 31, 2013, the Company recorded additional unproved property costs of $588,000 related to wells in progress and $158,000 related to additional investments in unproved properties. During the nine months ended December 31, 2013, $1,318,000 in costs related to wells and $341,000 related to acreage were transferred from unevaluated to depletable properties, in addition, there were $98,000 of lease expirations.

5. Long-Term Debt

At December 31, 2013, the Company had an outstanding balance of $8,000,000 on it's existing Credit Facility. Effective September 10, 2013, a redetermination of our allowable borrowing base was completed by the lender and our borrowing base was increased from $6,000,000 to $12,000,000. As of December 31, 2013, we were in compliance with all covenants as required by the Credit Facility.

6. Income Tax

The provision for income tax is comprised of:

	Three Months Ended					Nine Months Ended
	December 31,					December 31,
	2013			2012		2013		2012
	(Unaudited)			(Unaudited)		(Unaudited)		(Unaudited)
Current:
Federal	$	(30,000	)	$	13,000	$	25,000	$	36,000
State		2,000			1,000		17,000		4,000
Total current income tax		(28,000	)		14,000		42,000		40,000

Deferred:
Federal		307,000			80,000		782,000		149,000
State		17,000			7,000		45,000		12,000
Total deferred income tax		324,000			87,000		827,000		161,000

Income tax expense	$	296,000		$	101,000	$	869,000	$	201,000

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						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
Federal tax at statutory rate	$	417,000		$	160,000		$	1,264,000		$	451,000
State taxes, net of federal benefit		13,000			5,000			45,000			12,000
Excess percentage depletion		(184,000	)		(89,000	)		(494,000	)		(296,000	)
Other adjustments, net		50,000			25,000			54,000			34,000

Income tax expense	$	296,000		$	101,000		$	869,000		$	201,000
Effective rate expressed as a percentage
of income before income tax		24.1	%		21.4	%		23.4	%		15.2	%

The overall effective tax rate expressed as a percentage of book income before income tax for the three and nine months ended December 31, 2013, as compared to the corresponding periods in the prior year, varied due to a higher pre-tax income compared to the comparable prior periods, coupled with a change in excess percentage depletion and the impact of adjustments to agree to the tax returns that had been filed. For the current three and nine months ended December 31, 2013, pre-tax income was $1,229,000 and $3,719,000, respectively, compared to $471,000 and $1,327,000, repectively, for the comparative prior periods.

Net deferred tax assets and liabilities were comprised of:

	December 31,			March 31,
	2013			2013
	(Unaudited)
Deferred tax assets:
Statutory depletion carry-forward	$	2,062,000		$	1,467,000
Net operating loss carry-forward		1,337,000			-
Other accruals		92,000			131,000
Allowance for doubtful accounts		15,000			14,000

Gross deferred tax assets		3,506,000			1,612,000

Deferred tax liabilities:
Depletion, depreciation and intangible drilling costs		(7,304,000	)		(4,583,000	)

Gross deferred tax liabilities		(7,304,000	)		(4,583,000	)

Deferred tax liabilities, net	$	(3,798,000	)	$	(2,971,000	)

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 federal income tax returns for the prior three tax years of filings and state income tax returns for the prior four years of tax 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 our Annual Report on Form 10-K for the year ended March 31, 2013, 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 our 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 sales are unpredictable, and such volatility is expected. All of our production is sold at market prices. Obviously, if the commodity indexes fluctuate, the price that we receive for our oil and natural gas sales 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 (“Bank”) which provides an additional source of funds to pay our share of drilling and completion costs incurred on wells drilled and completed primarily in the Williston Basin, but also elsewhere. The initial borrowing base on the Credit Facility was $6 million. Among other provisions, the Credit Facility contains certain affirmative and negative covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. At the end of the quarter ending June 30, 2013, we were not in compliance with Credit Facility current ratio covenant. For further information concerning the Credit Facility and its terms, see our Form 8-K filed with the SEC on January 3, 2013.

Effective September 10, 2013, we entered into a Waiver and First Amendment to Credit Agreement (the “Amended Credit Facility”) with the Bank of Oklahoma in connection with a semiannual redetermination of the borrowing base. The redetermination resulted in an increase in the borrowing base from $6 million under the initial Credit Facility to $12 million under the Amended Credit Facility, which amount is subject to redetermination. The covenant violation was waived under terms of the Amended Credit Facility. As of December 31, 2013, we had an outstanding balance due of $8 million under the Amended Credit Facility and were in compliance with all covenants contained in the Amended Credit Facility. Our ability to remain in compliance with the financial covenants may be affected by events and other factors beyond our control, including market prices for our oil and gas and the rate at which the operators of projects in which we participate drill. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect our liquidity by rendering us unable to borrow further under the Amended Credit Facility. For further information concerning the Amended Credit Facility and its terms, see the Exhibits below in Part II – Item 6 of this Form 10-Q.

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 existing 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 means of obtaining additional financing.

Hedging. During the nine months ended December 31, 2013 and 2012, we did not participate in any hedging activities, nor did we have any open futures or option contracts.

Working Capital. At December 31, 2013, we had a working capital deficit of $545,000 (a current ratio of 0.92:1) compared to a working capital surplus at March 31, 2013 of $775,000 (a current ratio of 1.14:1). The decrease in current ratio is primarily a result of the use of accrued payables for the development and exploration of oil and gas properties and ongoing oil and gas operations.

Cash Flow. Cash provided by operating activities was $5,065,000 for the nine months ended December 31, 2013, compared to $1,982,000 for the nine months ended December 31, 2012. Changes in operating cash relate primarily to the increase in net income adjusted for non-cash expenses for the nine months ended December 31, 2013 compared to the comparable prior period ended December 31, 2012. Increases in deferred income tax expense and depletion primarily relate to the increase in the oil and gas property balances. The timing and payment of accounts payable, accrued and other liabilities, especially pertaining to capital expenditure outlays, 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, 2013, to $9,125,000 from $8,573,000 for the nine months ended December 31, 2012. This was the result of an increase in the number of wells drilled and completed during the current period compared to the comparable prior period, as explained in “Capital Expenditures” below.

Net cash provided by financing activities was $3,953,000 for the nine months ended December 31, 2013, compared to $1,970,000 for the nine months ended December 31, 2012. The increase is related to larger borrowings on our Credit Facility between periods for capital expenditures as further described in “Capital Expenditures” below.

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 nine months ended December 31, 2013, we spent $12,170,000 on various projects. This compares to $9,553,000 for the nine months ended December 31, 2012. During the nine months ended December 31, 2013, capital expenditures were comprised of drilling and completions of our wells producing as of period end (53%), participating in the drilling of ten wells with potential completion as of the fiscal year end (46%), and acquiring leasehold acreage (1%). The majority (92%) of capital expenditures were spent in North Dakota. The remainder was spent in other areas on drilling and completions, property improvements and leasehold acreage.

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

For the nine months ended December 31, 2013, we sold a salt water disposal well located in North Dakota for proceeds of $291,000 in the current quarter. These sales proceeds were received during the fiscal quarter ended December 31, 2013. We did not plug any wells during the nine months ended December 31, 2013.

Impact of Inflation and Pricing

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

Other Commitments

We do not have any other commitments beyond our office lease and software maintenance contracts.

Results of Operations

The following provides selected financial information and averages for the three and nine months ended December 31, 2013 and 2012.

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
Revenue
Oil	$	4,023,000	$	2,589,000	$	11,633,000	$	7,263,000
Gas 1		467,000		163,000		1,066,000		409,000
Total revenue 2		4,490,000		2,752,000		12,699,000		7,672,000

Total production expense 3		1,513,000		1,105,000		3,956,000		3,220,000

Gross profit	$	2,977,000	$	1,647,000	$	8,743,000	$	4,452,000

Depletion expense	$	1,009,000	$	559,000	$	2,719,000	$	1,284,000

Sales volume 4
Oil (Bbls)		47,153		31,549		126,826		89,717
Gas (Mcfs)		47,492		26,542		131,615		71,926

Average sales price 5
Oil (per Bbl)	$	85.32	$	82.06	$	91.72	$	80.95
Gas (per Mcf) 6	$	9.83	$	6.14	$	8.10	$	5.69

Average per BOE 4, 5, 7
Production expense 5	$	27.48	$	30.72	$	26.59	$	31.66
Gross profit 5	$	54.06	$	45.78	$	58.77	$	43.77
Depletion expense 5	$	18.32	$	15.54	$	18.28	$	12.62

1		Amount includes natural gas liquid (NGL) revenue. For the three months ended December 31, 2013 and 2012, the NGL revenue included in the gas revenue amount is $245,000 and $44,000, respectively. For the nine months ended December 31, 2013 and 2012, the NGL revenue included in the gas revenue amount is $462,000 and $122,000, respectively.

2		Amount does not include water service and disposal revenue. For the three and nine months ended December 31, 2013, this revenue amount is net of ($16,000) and $42,000, respectively, in well service and water disposal revenue, which would otherwise total $4,474,000 and $12,741,000, respectively, in revenue, compared to $82,000 and $318,000 in the respective periods ended December 31, 2012 to total $2,834,000 and $7,990,000 for the comparable three and nine month periods ended December 31, 2012. The ($16,000) in net revenue recorded for the three months ended December 31, 2013 represents the impact of the reversal of a revenue accrual recorded during the three month period ended September 30, 2013.

3		Overall lifting cost (oil and gas production costs, including production taxes and the cost of workovers)

4		Estimates of volumes are inherent in reported volumes to coincide with revenue accruals as a result of the timing of sales information reporting by third party operators.

5		Averages calculated based upon non-rounded figures.

6		Average gas sales price per Mcf is calculated by dividing total gas and NGL revenue by the gas sales volume per Mcf. For the three months ended December 31, 2013 and 2012, gas sales price per Mcf, exclusive of NGL revenues, was $4.67 per Mcf and $4.48 per Mcf, respectively. For the nine months ended December 31, 2013 and 2012, gas sales price per Mcf, exclusive of NGL revenues, was $4.59 per Mcf and $3.99 per Mcf, respectively.

7		Per equivalent barrel (6 thousand cubic feet, “Mcf”, of gas is equivalent to 1 barrel, “Bbl”, of oil)

Three months ended December 31, 2013 compared to three months ended December 31, 2012

Overview. Net income for the three months ended December 31, 2013, was $933,000 compared to net income of $370,000 for the three months ended December 31, 2012. The increase in net income resulted from the increase in oil and gas sales volumes and prices as described in “Revenues” and “Volumes and Prices” below which were partially offset by an increase in expenses for the three month period.

Revenues. Oil sales revenue increased $1,434,000 (55%) for the three months ended December 31, 2013 to $4,023,000 from $2,589,000 for the three months ended December 31, 2012, due to the increase in reported sales volumes and a higher realized price per barrel as described in “Volumes and Prices” below.

Gas sales revenue increased $304,000 (187%) for the three months ended December 31, 2013, compared to the three months ended December 31, 2012, as a result of the increase in reported sales volumes and a higher realized price per Mcf as described in “Volumes and Prices” below.

Volumes and Prices. Oil sales volumes increased by 49% for the three months ended December 31, 2013, compared to the three months ended December 31, 2012. In addition, the average price per barrel increased by 4% for the three months ended December 31, 2013 over the three months ended December 31, 2012. The increase in oil sales volumes for the three months ended December 31, 2013 when compared to the three months ended December 31, 2012 was the result of an increase in sales from newly producing wells, offset partially by declines in existing wells.

Gas sales volumes increased by 79% for the three months ended December 31, 2013, compared to the three months ended December 31, 2012. In addition, the average price per Mcf increased by 60% for the three months ended December 31, 2013, compared to the three months ended December 31, 2012. The increase in gas sales volumes for the three months ended December 31, 2013 when compared to the three months ended December 31, 2012 was the result of increased sales volumes from newly producing wells, coupled with a higher percentage of gas being sold from existing wells as midstream infrastructure is expanded, offset partially by declines in existing wells.

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

	Three Months Ended December 31,
	2013		2012

Lease operating costs	$	754,000	$	654,000
Workover costs		215,000		186,000
Production taxes		468,000		239,000
Transportation and other costs		76,000		26,000

Total production expense	$	1,513,000	$	1,105,000

Oil and gas production expense increased $408,000 (37%) for the three months ended December 31, 2013, as compared to the expenses for the three months ended December 31, 2012, 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 $15.07 for the three months ended December 31, 2013, compared to $18.90 for the three months ended December 31, 2012. While the total dollars spent on routine lease operating expense was 22% higher between the comparable periods, the costs are being divided over more BOE in the three months ended December 31, 2013 resulting in a lower cost per BOE.

As a percent of oil and gas sales revenue, routine LOE was 18% for the three months ended December 31, 2013, compared to 25% for the three months ended December 31, 2012. This decrease in cost in proportion to revenue was due to a combination of the increase in oil and gas prices, sales volume, and the number of producing wells between the comparable periods.

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 $29,000 (16%) for the three months ended December 31, 2013, compared to the respective period ended December 31, 2012. Consequently, workover costs in the third quarter of fiscal year 2014 decreased to $3.90 per BOE from $5.17 per BOE in the third quarter of fiscal 2013 due to the increase in production volumes between the comparable periods.

Production taxes for the three months ended December 31, 2013 increased 96% over the three months ended December 31, 2012, primarily due to the increase in oil and gas sales revenues. As a percent of oil and gas sales revenue, production taxes increased slightly to 10% compared to 9% in the prior comparable period. Because production tax rates vary from state to state, our average production tax rate will vary depending on the quantities sold from each state and the production tax rates, and incentives, in effect for those jurisdictions.

While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) increased during the current quarter in relation to the comparable period in the prior year, those costs are spread over larger reported BOE volumes for the three months ended December 31, 2013, compared to the three months ended December 31, 2012, causing the costs per BOE to decrease from $30.72 to $27.48.

Other Expenses. Depletion and depreciation increased $459,000 (80%) for the three months ended December 31, 2013, compared to the three months ended December 31, 2012. The increase in expense was a result of an increase in the pool of depletable property costs following the inclusion of capital costs associated with newly drilled and completed wells, as well as an increase in the costs related to future development of proved undeveloped wells between the comparable periods. Depletion and depreciation in the third quarter of fiscal year 2014 increased to $18.81 per BOE from $16.04 per BOE in the third quarter of fiscal 2013.

General and Administrative (“G&A”) expense decreased $41,000 (6%) for the three months ended December 31, 2013, over the expense for the three months ended December 31, 2012. While G&A expense decreased slightly during the current quarter in relation to the comparable period in the prior year, those costs are spread over larger reported BOE volumes, for the three months ended December 31, 2013, compared to the three months ended December 31, 2012, causing the costs per BOE to decrease from $18.60 to $11.40.

Income Tax. For the three months ended December 31, 2013, we recorded income tax expense of $296,000, as compared to $101,000 for the three months ended December 31, 2012. Our effective income tax rate was 24.1% and 21.4% for the three months ended December 31, 2013 and 2012, respectively. The overall effective tax rate expressed as a percentage of book income before income tax for the three months ended December 31, 2013, as compared to the same period in 2012, varied due to a higher pre-tax income compared to the comparable prior periods, coupled with a change in excess percentage depletion and the impact of adjustments to agree to the tax returns that had been filed. For the three months ended December 31, 2013, pre-tax income was $1,229,000 compared to $471,000 for the prior period.

Nine months ended December 31, 2013 compared to nine months ended December 31, 2012

Overview. Net income for the nine months ended December 31, 2013, was $2,850,000 compared to net income of $1,126,000 for the nine months ended December 31, 2012. The increase in net income resulted from the increase in oil and gas sales volumes and prices as described in “Revenues” and “Volumes and Prices” below which were partially offset by an increase in expenses for the nine month period.

Revenues. Oil sales revenue increased 60% for the nine months ended December 31, 2013, from $7,263,000 for the nine months ended December 31, 2012 to $11,633,000 for the current period, due to the increase in reported sales volumes and a higher realized price per barrel as described in “Volumes and Prices” below.

Gas sales revenue increased $657,000 (161%) for the nine months ended December 31, 2013, compared to the nine months ended December 31, 2012, as a result of the increase in reported sales volumes and a higher realized price per Mcf as described in “Volumes and Prices” below.

Volumes and Prices. Oil sales volumes rose by 41% for the nine months ended December 31, 2013, compared to the nine months ended December 31, 2012. The average price per barrel increased by 13% for the nine months ended December 31, 2013, compared to the nine months ended December 31, 2012. The rise in oil sales volumes for the nine months ended December 31, 2013 was the result of a significant contribution from 26 new gross producing oil wells in North Dakota since the comparable period in the prior year.

Gas sales volumes increased by 83% for the nine months ended December 31, 2013, compared to the nine months ended December 31, 2012. In addition, the average price per Mcf increased by 42% for the nine months ended December 31, 2013, compared to the nine months ended December 31, 2012. The increase in gas sales volumes for the nine months ended December 31, 2013 when compared to the nine months ended December 31, 2012 was the result of increased sales volumes from newly producing wells, coupled with a higher percentage of gas being sold from existing wells as midstream infrastructure is expanded, offset partially by declines in existing wells.

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

	Nine Months Ended December 31,
	2013		2012

Lease operating costs	$	2,129,000	$	1,903,000
Workover costs		476,000		573,000
Production taxes		1,208,000		697,000
Transportation and other costs		143,000		47,000

Total production expense	$	3,956,000	$	3,220,000

Oil and gas production expense increased $736,000 (23%) for the nine months ended December 31, 2013, over the expenses for the nine months ended December 31, 2012, 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 $15.27 for the nine months ended December 31, 2013, compared to $19.17 for the nine months ended December 31, 2012. While the total dollars spent on routine lease operating expense was 17% higher between the comparable periods, the costs are being divided over more BOE in the nine months ended December 31, 2013 resulting in a lower cost per BOE.

As a percent of oil and gas sales revenue, routine LOE was 18% for the nine months ended December 31, 2013 and 25% for the nine months ended December 31, 2012. This decrease of routine LOE in proportion to revenue was due to a combination of the increase in oil and gas prices, sales volume, and the number of producing wells between the comparable periods.

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 $97,000 (17%) for the nine months ended December 31, 2013, compared to the respective period ended December 31, 2012. The workover costs were spread over increased sales volumes, resulting in a decrease in workover costs per BOE in the nine months ended December 31, 2013 to $3.20 from $5.63 per BOE in the nine months ended December 31, 2012.

Production taxes for the nine months ended December 31, 2013, increased 73% over the nine months ended December 31, 2012, primarily due to the increase in oil and gas sales revenues. As a percent of oil and gas sales revenue, production taxes increased to 10% compared to 9% with 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, and incentives, in effect for those jurisdictions.

While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) increased during the current period, those costs are spread over greater reported BOE volumes, for the nine months ended December 31, 2013, compared to the nine months ended December 31, 2012, causing the cost per BOE to decline from $31.66 to $26.59.

Other Expenses. Depletion and depreciation increased $1,470,000 (110%) for the nine months ended December 31, 2013, compared to the nine months ended December 31, 2012. The increase in expense was a result of an increase in the pool of depletable property costs following the inclusion of capital costs associated with newly drilled wells, as well as an increase in the costs related to future development of proved undeveloped wells between the comparable periods. Depletion and depreciation in the nine months ended December 31, 2013 increased to $18.84 per BOE from $13.10 per BOE in the nine months ended December 31, 2012.

General & Administrative (“G&A”) expense increased $3,000 (0.2%) for the nine months ended December 31, 2013, over the expense for the nine months ended December 31, 2012. This slight increase in costs is comprised primarily of increases in compensation-related expenses.

The slight increase in G&A costs, coupled with a 46% increase in BOE sales for the nine months ended December 31, 2013, compared to the nine months ended December 31, 2012, resulted in the 32% decrease in expense per BOE from $19.44 for the nine months ended December 31, 2012, to $13.31 for the nine months ended December 31, 2013.

Income Tax. For the nine months ended December 31, 2013, we recorded income tax expense of $869,000, as compared to $201,000 for the nine months ended December 31, 2012. Our effective income tax rate was 23.4% and 15.2% for the nine months ended December 31, 2013 and 2012, respectively. The overall effective tax rate expressed as a percentage of book income before income tax for the nine months ended December 31, 2013, as compared to the same period in 2012, was higher due primarily to higher 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 December 31, 2013. 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, 2013, 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 third quarter of the fiscal year ending March 31, 2014:

	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, 2013 – October 31, 2013		9	$	17.17		9		103,275
November 1, 2013 – November 30, 2013		21	$	16.76		21		103,254
December 1, 2013 – December 31, 2013		—	$	—		—		103,254
Total		30		16.88		30

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. On November 11, 2013, the Board approved a motion that allowed for up to $5,000 per year to be used to buy back blocks of 99 shares or less. During the quarter ended December 31, 2013, 30 shares were repurchased at an average price of $16.88 under the share buyback program and 103,254 shares (10,299 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
10.1		Credit Agreement dated as of December 21, 2012 between Earthstone Energy, Inc., as Borrower, and BOKF, N.A. d/b/a Bank of Oklahoma, as Lender (filed as Exhibit to Form 8-K dated December 21, 2012, as filed with the SEC on January 2, 2013, and incorporated by reference herein).

10.2*		Waiver and Amendment to Credit Agreement dated effective as of September 10, 2013 between Earthstone Energy, Inc., as Borrower, and BOKF, N.A. d/b/a Bank of Oklahoma, as Lender.

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..INS**		XBRL Instance Document.

101..SCH**		XBRL Schema Document.

101..CAL**		XBRL Calculation Linkbase Document

101..DEF**		XBRL Definition Linkbase Document.

101.LAB**		XBRL Label Linkbase Document.

101.PRE**		XBRL Presentation Linkbase Document.

* Filed herewith

** Attached as Exhibit 101 to this report are the following materials 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. Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

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.
By: /s/ Ray Singleton
Ray Singleton
President and Chief Executive Officer

By: /s/ Paul D. Maniscalco
Paul D. Maniscalco
Interim Chief Financial Officer

Date: February 13, 2014