Miller Energy Resources CORRESP Correspondence with SEC

Miller Energy Resources

9721 Cogdill Road, Suite 302

Knoxville, TN 37932

O: (865) 223-6575

F: (865) 691-8209

July 13, 2012

'CORRESP'

Division of Corporation Finance

United States Securities and Exchange Commission

100 F Street N.E.

Washington, D.C. 20549



Attention:	Ron Winfrey Robert Carroll
	Ethan Horowitz, Branch Chief



Re:	Miller Energy Resources, Inc. (formerly Miller Petroleum, Inc.)
	Form 10-K/A for Fiscal Year Ended April 30, 2010 Filed July 28, 2010 Form 10-K/A for Fiscal Year Ended April 30, 2011 Filed August 29, 2011
	File No. 001-34732

Gentlemen:

As discussed in our conference call earlier today, Miller Energy Resources, Inc. (the “Company”) is providing the following supplemental response to the comment letter dated May 1, 2012, from the staff of the Division of Corporation Finance (the “Staff”) of the U.S. Securities and Exchange Commission (the “SEC”). We previously responded to that comment letter on June 21, 2012. In that response letter, we indicated that we intended to disclose revisions related to the recharacterization of RU-17 in the Company’s Form 10-K for its fiscal year ended April 30, 2012. In this supplemental comment letter, we set forth in greater detail the manner in which we intend to disclose those revisions.

Preliminarily, as you requested, the following is list of persons who participated in this morning’s call on behalf of the Company:

From the Company: Scott M. Boruff, Chief Executive Officer; David J. Voyticky, President and

Acting Chief Financial Officer; David M. Hall, Chief Executive Officer of the Company’s wholly-owned subsidiary, Cook Inlet Energy, LLC; Kurt C. Yost, Esq. Senior Vice President and General Counsel; Charles B. Lobetti, III, Controller; Anna East Corcoran, Esq., Assistant General Counsel; and Jessica L. Cumbee, Law Clerk.

From Pearlman Schneider LLP, the Company’s Securities Counsel: James M. Schneider, Esq.

From KPMG LLP, the Company’s Registered Public Accounting Firm: John Riordan, Partner; Christopher O. Champion, Partner; Samuel L. Bennett, Senior Manager; and Paige C. Walton, Senior Associate.

Supplemental Response

Attached as Exhibit A is the disclosure we would propose including in our Form 10-K for the year ended April 30, 2012, removing RU-17 from proved reserves and making the other corrections to our proved reserves indicated on this morning’s conference call. This draft disclosure is in its final stages of review, and while we do not anticipate significant changes, we respectfully submit to the Staff that further adjustments may be made prior to our filing.

In addition, as stated in our June 21, 2012 response, the Company proposes to file along with its Form 10-K for the year ended April 30, 2012, the corrected revised reserve reports (attached to our June 21, 2012 response letter as Exhibits A and B thereto).

We respectfully request an opportunity to discuss this response letter further with the Staff if, following a review of this information, the Staff does not concur with our proposed course of action. If you have further questions or comments, or if you require additional information, please do not hesitate to contact the undersigned by telephone at (865) 223-6575 or by facsimile at (865) 691-8209.

We acknowledge that (i) the Company is responsible for the adequacy and accuracy of the disclosures in the Form 10-K and Form 10-Q; (ii) Staff comments or changes to disclosure in response to Staff comments do not foreclose the SEC from taking any action with respect to the filing; and (iii) the Company may not assert Staff comments as a defense in any proceedings initiated by the SEC or any person under the federal securities laws of the United States.



	Sincerely,

	/s/ Kurt C. Yost
	Kurt C. Yost Senior Vice President and General Counsel

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The Company made revisions to its unaudited supplemental oil and gas disclosures for the fiscal years ended April 30, 2011 and 2010. The revisions primarily related to: a) one well in our Redoubt Field in the Cook Inlet Region which was previously reported as proved undeveloped reserves has now been reclassified as unproved reserves, and b) a change in the estimated income tax rate. In addition, we corrected other computational errors in our calculations of the April 30, 2011 and 2010 unaudited disclosures, which did not result in changes to the Company's standardized measure calculations.

The following tables show our capital and operational costs for fiscal years 2012, 2011 and 2010:

a. Capitalized Costs Relating to Oil and Gas Producing Activities at April 30, 2012, 2011 and 2010 are as follows:



	2012			2011			2010
	(In thousands)
Natural gas and oil properties:
Proved properties	$	321,066		$	314,706		$	304,760
Unproved properties	182,704			182,220			181,165
	503,770			496,926			485,925
Accumulated depletion	(27,968		)	(14,874		)	(3,156		)
Net capitalized costs	$	475,802		$	482,052		$	482,769

The following summarizes the revisions for fiscal years 2011 and 2010. The revision to fiscal 2011 and 2010 capital cost tables primarily relates to the reclassification of the Redoutbt proved undeveloped reserves to unproven reserves.



	2011							2011
	As Reported			Revisions				As Adjusted
	(In thousands)
Natural gas and oil properties:
Proved properties	$	344,250		$	(29,544	)	)	$	314,706
Unproved properties	152,058			30,162				182,220
	496,308			618				496,926
Accumulated depletion	(14,439		)	(435		)		(14,874		)
Net capitalized costs	$	481,869		$	183			$	482,052



	2010							2010
	As Reported			Revisions				As Adjusted
	(In thousands)
Natural gas and oil properties
Proved properties	$	333,666		$	(28,906	)	)	$	304,760
Unproved properties	152,259			28,906				181,165
	485,925			—				485,925
Accumulated depletion	(3,156		)	—				(3,156		)
Net capitalized costs	$	482,769		$	—			$	482,769

b. Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities:



	2012		2011		2010
	(In thousands)
Property acquisition costs
Proved properties	$	—	$	—	$	2,052
Unproved properties	785		1,009		1,611
Acquisition costs	785		1,009		3,663
Exploration costs	180		—		—
Development costs	6,773		10,265		4,153
Total	$	7,738	$	11,274	$	7,816

c. Results of Operations for Producing Activities:



	2012			2011			2010
	(In thousands)
Production revenues	$	32,493		$	20,525		$	4,437
Oil and gas operating costs	(14,861		)	(9,703		)	(2,738		)
Depletion	(13,094		)	(11,002		)	(1,741		)
Results of operations for producing activities (excluding corporate overhead and interest costs)	$	4,538		$	(180	)	$	(42	)

d. Reserve Quantity Information (Unaudited)

The following reserve quantity information was derived from reserve and engineering reports prepared for the Company by various third parties. The reserve and engineering reports for both Alaska and Tennessee properties were prepared by Ralph E. Davis Associates, Inc. for the year ended April 30, 2012. Ralph E. Davis Associates, Inc. also prepared the reserve and engineering reports for our Alaska properties for the years ended April 30, 2011 and 2010. Reserve and engineering reports for our Tennessee properties were prepared by Lee Keeling and Associates, Inc. for the years ended April 30, 2011 and 2010.

The following schedule estimates proved oil and natural gas reserves attributable to the Company. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil (Bbls) and thousands of cubic feet of natural gas (Mcf). Geological and engineering estimates of proved oil and natural gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates reported represent the most accurate assessments possible, these estimates are by their nature generally less precise than other estimates presented in connection with financial statement disclosures.



	Oil (Bbls)		Gas (Mcf)
	(In thousands)
Proved reserves
Balance, April 30, 2009	53		1,864
Discoveries and extensions	—		—
Revisions of previous estimates	65		(1,082	)
Acquisitions	9,211		4,831
Production	(62	)	(154	)
Balance, April 30, 2010	9,267		5,459
Discoveries and extensions	—		1,309
Revisions of previous estimates	(46	)	156
Sales of reserves in place	—		(3,342	)
Production	(273	)	(339	)
Balance, April 30, 2011	8,948		3,243
Discoveries and extension	94		1,850
Revisions of previous estimates	(124	)	(359	)
Sales of reserves in place	—		—
Production	(384	)	(177	)
Balance, April 30, 2012	8,534		4,557
Proved developed reserves at April 30, 2012	2,325		2,601
Proved developed reserves at April 30, 2011	2,461		2,441
Proved developed reserves at April 30, 2010	2,666		1,737
Proved undeveloped reserves at April 30, 2012	6,209		1,956
Proved undeveloped reserves at April 30, 2011	6,487		802
Proved undeveloped reserves at April 30, 2010	6,601		3,722

The following summarizes the corrections for fiscal years 2011 and 2010:



	Oil (Bbls)				Oil (Bbls)
	As Reported		Revisions		As Adjusted
	(In thousands)
Proved reserves
Balance, April 30, 2009	53		—		53
Discoveries and extensions	—		—		—
Revisions of previous estimates	65		—		65
Acquisitions	10,288		(1,077	)	9,211
Production	(62	)	—		(62	)
Balance, April 30, 2010	10,344		(1,077	)	9,267
Discoveries and extensions	—		—		—
Revisions of previous estimates	(64	)	18		(46	)
Sales of reserves in place	—		—		—
Production	(273	)	—		(273	)
Balance, April 30, 2011	10,007		(1,059	)	8,948
Proved developed reserves at April 30, 2011	2,471		(10	)	2,461
Proved developed reserves at April 30, 2010	2,666		—		2,666
Proved undeveloped reserves at April 30, 2011	7,536		(1,049	)	6,487
Proved undeveloped reserves at April 30, 2010	7,678		(1,077	)	6,601



	Gas (Mcf)				Gas (Mcf)
	As Reported		Revisions		As Adjusted
	(In thousands)
Proved reserves
Balance, April 30, 2009	1,864		—		1,864
Discoveries and extensions	—		—		—
Revisions of previous estimates	(1,082	)	—		(1,082	)
Acquisitions	4,831		—		4,831
Production	(154	)	—		(154	)
Balance, April 30, 2010	5,459		—		5,459
Discoveries and extensions	1,309		—		1,309
Revisions of previous estimates	(15	)	171		156
Sales of reserves in place	(3,342	)	—		(3,342	)
Production	(339	)	—		(339	)
Balance, April 30, 2011	3,072		171		3,243
Proved developed reserves at April 30, 2011	2,488		(47	)	2,441
Proved developed reserves at April 30, 2010	1,737		—		1,737
Proved undeveloped reserves at April 30, 2011	584		218		802
Proved undeveloped reserves at April 30, 2010	3,722		—		3,722

Acquisitions, as noted above, were comprised of several entities. The acquisition of ("KTO") included approximately 35,325 leased acres located on the Chattanooga Shale and 153 natural gas and oil producing wells. On June 18, 2009 the Company acquired 100% of the stock of East Tennessee Consultants, Inc., a Tennessee corporation ("ETC") and 100% of the membership interests in East Tennessee Consultants II, LLC, a Tennessee limited liability company ("LLC") from the owners of these entities. The acquisition included 221 producing oil and gas wells and consisted of approximately 4,442 acres. On December 10, 2009, the Company acquired 100% of the membership interests in Cook Inlet Energy, LLC, an Alaska limited liability company from the owners of this entity

and simultaneously acquired former Alaskan operations of Pacific Energy Resources ("Pacific Energy") through a Delaware Chapter 11 Bankruptcy proceeding. The purchased assets include the West McArthur River oil field, the West Foreland natural gas field, and the Redoubt unit with the Osprey offshore platform, all located along the west side of the Cook Inlet. Also included in the asset purchase are 602,000 acres of oil and gas leases, which includes 471,474 acres under the Susitna Basin Exploration License.

With the closing of these acquisitions, our management is now able to focus the majority of its efforts on growing our company. We are continuing to focus our short-term efforts on three distinct areas, including:


•	Increase our overall oil and gas production through maintenance and repairs of nonperforming or underperforming wells,


•	Organically growing production through drilling for our own benefit on existing leases and under license rights, leveraging our 100,000 plus well log database and approximately 700,000 acres which are either under lease or part of our Alaska Susitna Basin Exploration Licenses, with a view towards retaining the majority of working interest in the new wells, and


•	Expanding our contract drilling and service capabilities and revenues, including drilling and service contracts with third parties.

We have budgeted for capital expenditures of $50 million to $100 million in fiscal 2013; $24 million of this amount is budgeted for restoring additional production from our offshore Redoubt field in Alaska and $51 million will be used for onshore exploratory oil and natural gas projects in Alaska and Tennessee. We anticipate we will draw on our new Apollo Investment Corporation credit facility and raise additional equity as needed to provide the required capital. In addition, we will utilize the increased cash flow from increased production.

The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company's proved developed reserves for the years ended April 30, 2012, 2011 and 2010. All estimates were prepared by third party reserve and engineering firms. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at April 30, 2012, 2011 and 2010, it should be emphasized that such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of the Company's recoverable reserves or in estimating future results of operations.

Each of the engineering reports also projected future cash flows from our net reserves and the present value, discounted at 10% per annum. Future cash flows are based upon gross income from future production, less direct operating expenses and taxes. Estimated future capital for development costs was also deducted from gross income at the time it will be expended. No allowance was made for depletion, depreciation, income taxes or administrative expense. In the following table, the price per barrel of oil was $102.30 and the price per MMcf of natural gas was $6.37 for the Cook Inlet reserves and $87.68 per barrel of oil and $2.22 per MMcf of natural gas for the Appalachian region reserves. In each instance these prices are computed in accordance with the SEC's rule and represent the average fiscal year prices.

Operating costs and production taxes are estimated based on current costs with respect to producing gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved.

The future net revenue information assumes no escalation of costs or prices, except for gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

Standardized measures of discounted future net cash flows at April 30, 2012, 2011 and 2010 are as follows:



	2012			2011			2010
	(In thousands)
Future cash flows	$	894,027		$	657,564		$	597,654
Future production costs and taxes	(158,938		)	(119,653		)	(120,934		)
Future development costs	(75,332		)	(79,007		)	(45,632		)
Future income tax expense	(217,312		)	(149,388		)	(143,430		)	)
Future cash flows	442,445			309,516			287,658
Discount at 10% for timing of cash flows	(139,242		)	(102,715		)	(99,365		)
Discounted future net cash flows from proved reserves	$	303,203		$	206,801		$	188,293

The following summarizes the corrections for fiscal years 2011 and 2010:



	2011						2011
	As Reported			Revisions			As Adjusted
	(In thousands)
Future cash flows	$	732,002		$	(74,438	)	$	657,564
Future production costs and taxes	(126,060		)	6,407			(119,653		)
Future development costs	(93,249		)	14,242			(79,007		)
Future income tax expense	(88,079		)	(61,309		)	(149,388		)
Future cash flows	424,614			(115,098		)	309,516
Discount at 10% for timing of cash flows	(177,677		)	74,962			(102,715		)
Discounted future net cash flows from proved reserves	$	246,937		$	(40,136	)	$	206,801



	2010						2010
	As Reported			Revisions			As Adjusted
	(In thousands)
Future cash flows	$	662,582		$	(64,928	)	$	597,654
Future production costs and taxes	(123,879		)	2,945			(120,934		)
Future development costs	(50,225		)	4,593			(45,632		)
Future income tax expense	(96,926		)	(46,504		)	(143,430		)
Future cash flows	391,552			(103,894		)	287,658
Discount at 10% for timing of cash flows	(153,356		)	53,991			(99,365		)
Discounted future net cash flows from proved reserves	$	238,196		$	(49,903	)	$	188,293

Of the Company's total proved reserves as of April 30, 2012, 2011 and 2010, approximately 17%, 23% and 24%, respectively, were classified as proved developed producing, 21%, 17% and 6%, respectively, were classified as proved developed non-producing and 62%, 60% and 70%, respectively, were classified as proved undeveloped. All of the Company's reserves are located in the continental United States.

The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves for April 30, 2012, 2011 and 2010.



	April 30,
	2012			2011			2010
	(In thousands)
Balance, beginning of year	$	206,801		$	188,293		$	1,535
Sales, net of production costs and taxes	(17,632		)	(11,383		)	(2,064		)
Changes in prices and production costs	116,689			33,625			1,327
Extensions, discoveries and improved recovery, less related costs	58,906			4,592			—
Purchase of reserves in place	—			—			278,536
Changes in estimated future development costs	7,641			(26,032		)	1,013
Development costs incurred	6,773			10,265			4,153
Revisions of previous quantity estimates	(42,857		)	(555		)	(530		)
Net changes in income taxes	(48,571		)	(5,397		)	(92,139		)
Sales of reserves in place	—			(1,470		)	—
Accretion of discount	30,503			28,112			222
Changes in timing and other	(15,050		)	(13,249		)	(3,760		)
Balance, end of year	$	303,203		$	206,801		$	188,293

The following summarizes the corrections for fiscal years 2011 and 2010:



	2011						2011
	As Reported			Revisions			As Adjusted
	(In thousands)
Balance, beginning of year	$	238,196		$	(49,903	)	$	188,293
Sales, net of production costs and taxes	(10,823		)	(560		)	(11,383		)
Changes in prices and production costs	26,423			7,202			33,625
Extensions, discoveries and improved recovery, less related costs	4,592			—			4,592
Changes in estimated future development costs	(41,745		)	15,713			(26,032		)
Development costs incurred	10,265			—			10,265
Revisions of previous quantity estimates	26,689			(27,244		)	(555		)
Net changes in income taxes	8,847			(14,244		)	(5,397		)
Sales of reserves in place	(1,470		)	—			(1,470		)
Accretion of discount	33,512			(5,400		)	28,112
Changes in timing and other	(47,549		)	34,300			(13,249		)
Balance, end of year	$	246,937		$	(40,136	)	$	206,801



	2010						2010
	As Reported			Revisions			As Adjusted
	(In thousands)
Balance, beginning of year	$	1,535		$	—		$	1,535
Sales, net of production costs and taxes	(1,699		)	(365		)	(2,064		)
Changes in prices and production costs	298,306			(296,979		)	1,327
Purchase of reserves in place	314,652			(36,116		)	278,536
Changes in estimated future development costs	(44,887		)	45,900			1,013
Development costs incurred	4,153			—			4,153
Revisions of previous quantity estimates	(293,699		)	293,169			(530		)
Net changes in income taxes	(95,381		)	3,242			(92,139		)
Accretion of discount	308			(86		)	222
Changes in timing and other	54,908			(58,668		)	(3,760		)
Balance, end of year	$	238,196		$	(49,903	)	$	188,293

Miller Energy Resources (MILL) Inactive CORRESPCorrespondence with SEC