Response Letter

CORRESP 1 filename1.htm Response Letter


	Miller Energy Resources
	9051 Executive Park Drive
	Suite 103
	Knoxville, TN 37923
	O: (865) 223-6575
	F: (865) 691-8209
	paul@millerenergyresources.com

May 9, 2011

'CORRESP'

Division of Corporation Finance

United States Securities and Exchange Commission

100 F Street N.E.

Washington, D.C. 20549


Attention:	Robert Carroll
	Ethan Horowitz, Branch Chief


Re:	Miller Petroleum, Inc.
	Form 10-K for the year ended April 30, 2010 Filed July 28, 2010
	File No. 001-34732

Ladies and Gentlemen:

Miller Energy Resources, Inc. (formerly Miller Petroleum, Inc.) (the “Company”) is in receipt of the staff’s comment letter dated April 14, 2011. Following are the Company’s responses to the staff’s comments contained in such letter.

Based on our review of the Staff’s comment letter, and as further described herein, and given the proximity of receipt of these comments to our fiscal year end, as indicated in certain responses below, we respectfully propose to make appropriate clarifications or modifications to certain of our disclosures in our Annual Report on Form 10-K for the fiscal year ended April 30, 2011, which we currently expect to file by July 14, 2011.

Form 10-K for Fiscal Year Ended April 30, 2010

Statement of Operations, page F-4


1.	Please tell us and disclose how your gain on acquisitions in the amount of $461,111,924 was calculated for your fiscal year ended April 30, 2010. Please be detailed in your response. We note disclosure related to the gains on specific acquisitions in your footnotes, but cannot reconcile those amounts to the total gain recognized on the face of your statement of operations.

RESPONSE:

The gain relates to three different acquisitions: Ky-Tenn Oil, Inc. (“KTO”), East Tennessee Consultants, Inc. and East Tennessee Consultants II, LLC (collectively, “ETC”) and Cook Inlet Energy, LLC (“CIE”).


KTO	$	990,019
ETC		1,409,609
CIE		458,712,296
Total	$	461,111,924

Please see our responses to comments 3, 4, 5 and 6 for how each bargain purchase gain was calculated.

Note 1. Organization and Description of Business, page F-8


2.	We note you operate as one reportable business segment based on similarity of activities. We also note your business activities include oil and gas production, onshore drilling services, and other engineering services. Tell us and disclose in detail how you have evaluated your operating segments under ASC Subtopic 250-10-50 to conclude you have one reportable segment.

RESPONSE:

The Company’s chief operating decision maker reviews the operating results of the Company on a consolidated basis to make decisions about allocating resources and assessing performance. As a result, the Company has one operating segment under the provisions of ASC Subtopic 280-10-50. We will clarify our disclosure of how we evaluate our operating segments in future filings through the addition of the following disclosure:

The Company’s chief operating decision maker and our Board of Directors review the operating results of the Company on a consolidated basis when making decisions about allocating resources and assessing performance. As a result, the Company has one operating segment under the provisions of ASC Subtopic 280-10-50.

We note that although the Company has ancillary revenue from drilling, the majority of our drilling activities for the fiscal year ended April 30, 2010 were performed on our own properties. Drilling and service related activities performed on behalf of third parties largely relate to optimization of unused capacity and are not a strategic focus of the Company. As such, the operating results of these activities are not regularly evaluated by the chief operating decision maker on a standalone basis.

Note 6. Acquisitions

KTO Acquisition, page F-14

We note a third-party analysis was performed to determine the fair value of the assets acquired from Ky-Tenn Oil, Inc. (“KTO”) in June 2009, and the original value was determined to be $252,455. We also note an additional analysis was completed to determine the value of all undeveloped reserves for the acquired acreage during the quarter ended October 31, 2009 and you recorded a subsequent gain of $1,057,564 on this transaction. Please tell us and disclose the following:


	·	The total consideration you paid for this acquisition;
	·	Who performed the additional fair value analysis on the acquired property;
	·	Why a second valuation was performed subsequent to the original third-party analysis;
	·	The factors behind the significant increase in valuation and the calculation of the subsequent gain;
	·	How the undeveloped reserves were valued and if they were included in the original analysis; and
	·	Provide a detailed analysis on how you determined this was an asset purchase only and pro forma information was not required.

RESPONSE:


	·	The purchase price was 1,000,000 shares of our common shares on June 8, 2009 when the stock closed at $0.32 per share, resulting in consideration of $320,000.
	·	Lee Keeling and Associates, Inc. (“LKA”), an independent petroleum engineering firm, performed the fair value analysis. At the time of our Form 10-Q filing, LKA had completed and provided to us its fair value analysis for proved developed reserves, and the PV-10 value was $252,455, which was recorded. Because we completed the KTO and ETC acquisitions in the same quarter, LKA was unable to complete the assessment of undeveloped reserves prior to the Company’s deadline for filing its July 31, 2009 Form 10-Q. In the July 31, 2009 Form 10-Q, we disclosed that we were still determining the value of undeveloped reserves and anticipated we would retroactively adjust our allocation of fair value to the assets acquired and liabilities assumed when the final allocations were completed.


	·	During the next quarter ended October 31, 2009, LKA completed its determination of the value of all undeveloped reserves, resulting in a gain of $1,057,564 during the quarter. Such amount, combined with a $67,545 loss recorded during the quarter ended July 31, 2009, resulted in a net pre-tax gain of $990,019 being recorded for the fiscal year ended April 30, 2010.

There was no second valuation performed, just a completion of the first valuation. The Company believes it articulated this in the following sentence in the KTO Acquisition Note 6 appearing on page F-15 of our Form 10-K for April 30, 2010 “Subsequently, we completed the determination of the value of all undeveloped reserves for this acreage during the quarter ended October 31, 2009 and accordingly we recorded an additional gain of $1,057,564 on this transaction.”


	·	The valuation of undeveloped reserves was not completed in time for inclusion in the quarter ended July 31, 2009 (as described above). These reserves were also valued by LKA and based on geosciences and engineering data, are less likely to be recoverable than developed reserves but could potentially be recovered by drilling wells on undeveloped portions of KTO’s properties. The undeveloped reserves included 31 locations, with 29 wells offsetting these locations of which 16 wells had no record of production. Recoveries from the 13 offsets that did have recorded production indicated that the average recovery from wells that produced oil was 8,924 barrels of oil. Because of the scarcity of meaningful well information, LKA concluded the average recoveries from oil and gas wells in the area offer the only reliable means of estimating recoveries that might be obtained from wells to be drilled in this area. LKA also prepared its report utilizing methods and procedures regularly used by petroleum engineers to estimate oil and gas reserves for properties of this type and character. Some of these factors include prudent operation, compression of gas when needed, market demands, installation of lifting equipment and remedial work when required.
	·	As we disclosed on page 39 (Recent Accounting Pronouncements) of the April 30, 2010 Form 10-K, we accounted for each of our fiscal 2010 acquisitions, including KTO, as business combinations, and applied the provisions of ASC Subtopic 805-20. We acknowledge that our description of the transaction in footnote 6 is confusing due to the fact that we described the transaction as an “acquisition of certain assets” and will clarify the disclosure in future filings. We determined that pro-forma information related to this acquisition was not required (or useful to investors) due to the fact that this business combination was not material in relation to our consolidated financial statements. As 92 of the 153 wells acquired were shut in, and approximately 81% of the value of the well interests acquired were for undeveloped locations, pro-forma results would not have differed materially from actual results. This was the basis for our assertion stated on page F-15 of the April 30, 2010 Form 10-K: “No additional supplemental pro-forma information with regards to results of operations have been provided as the KTO acquisition was a purchase of select assets only.”

The fair value of the assets acquired less the liabilities assumed exceeded the fair value of the consideration tendered by $990,019; hence a bargain purchase gain was recorded. This bargain purchase gain has been presented in our statement of operations as a component of other income “gain on acquisitions.” The net gain of $643,512 was calculated as follows:


Cash	$	196,682
Oil & Gas Properties		1,310,019
Payables		(196,682	)
FV of Equity Issued		(320,000	)
Pre-tax Gain	$	990,019
Deferred Taxes		(346,507	)
Net Gain	$	643,512

ETC Acquisition, page F-15

We note your acquisition of East Tennessee Consultants, Inc. (“ETC”). Please tell us if your total consideration for this acquisition was the 1,000,000 shares of common stock issued for a total value of $250,000. Tell us specifically how you valued this acquisition under the FASB guidance and cite the guidance used. Tell us how you calculated the bargain purchase gain of $828,745 and where that gain was recorded in your financial statements.

RESPONSE:

In June 2009 we issued 1,000,000 shares of our common stock to acquire 100% ownership of ETC, two related entities. On June 18, 2009, the date we acquired ETC, the market price of our common stock was $0.25 per share; therefore the fair value consideration tendered to acquire ETC was $250,000.

ASC Topic 805, paragraphs 805-30-25-2, 3 and 4 and 805-30-30-4 and 5, discuss the parameters whereby a gain from bargain purchase is to be recorded if the net aggregate fair value of identified assets acquired and the liabilities assumed exceed the aggregate fair value of the consideration tendered. LKA assisted in our evaluation of the fair value of the oil and gas well interests acquired and another appraiser assisted us in determining a fair value of the real estate acquired, while we performed our own evaluations without outside assistance on the remaining assets acquired and liabilities assumed.

The fair value of the assets acquired less the liabilities assumed exceeded the fair value of the consideration tendered by $1,409,609; hence a bargain purchase gain was recorded. This bargain purchase gain has been presented in our statement of operations as a component of other income “gain on acquisitions.” The net gain of $828,745 was calculated as follows:


Cash	$	203,993
Receivables		24,904
Fixed Assets		313,458
Oil & Gas Properties		1,319,140
Other assets		874
Payables		(202,760	)
FV of Equity Issued		(250,000	)
Pre-tax Gain	$	1,409,609
Deferred taxes		(580,864	)
Net Gain	$	828,745

Alaska Acquisition, page F-15

We note your acquisition on December 10, 2009 of the Alaskan assets of Pacific Energy Resources, (“Pacific Energy”) which were valued at more than $479 million through a Delaware Chapter 11 bankruptcy proceeding. We note the acquisition included $215 million in proven energy reserves, $122 million in probable energy reserves and $31 million in possible energy reserves, providing total reserves of $368 million. Please provide the following information:


	·	Who performed the valuation of these reserves;
	·	A detailed analysis of how the value of each component of acquired reserves was determined;
	·	Tell us and disclose the values of the remaining assets acquired that make up the balance of the total amount of $479 million;
	·	The total consideration you paid for the asset acquisition;
	·	The calculation and your accounting for the bargain purchase gain in the amount of $274,821,626; and
	·	The calculation and your accounting for the deferred income taxes payable in the amount of $184,703,206.

RESPONSE:


	·	Ralph E. Davis Associates, Inc., an independent petroleum engineering firm, performed the evaluation of the oil and natural gas reserves. Beecher Carlson, a third party valuation specialist, performed the appraisal of the fixed assets.
	·	For Proved Producing Reserves estimates were made generally using performance methods, the resultant values were then compared to volumetric calculations for reasonableness. Proved Behind Pipe and Proved Undeveloped Reserves were determined volumetrically. Proved Behind Pipe Reserves are from reservoirs that have either been tested or have produced previously. Proved Undeveloped Reserves are either twin wells to previously drilled, tested wells or are one location offsets to producing wells. Probable Reserves are volumetrically determined and are generally one additional location from producing wells. Possible reserves are from locations one location out from probable locations. See pages 1 through 5 on the attached April 30, 2010 report from Ralph E. Davis Associates, Inc. for analysis information and a breakdown of the $368 million.
	·	Assets acquired consisted of the following:


Oil and Gas Properties	$	368,035,281
Restricted Cash		1,789,995
Inventory		212,228
Fixed Assets		110,516,500
Total	$	480,554,004


	·	Total consideration paid for the assets consisted of the following:


Cash paid	$	2,250,000
FV of Equity Issued		2,071,657
Cure amounts (payables)		1,001,252
Total	$	5,322,909


	·	Calculation of the bargain purchase gain is as follows:


Inventory	$	212,228
Fixed Assets		110,516,500
Oil & Gas Properties		368,035,281
Restricted Cash		1,789,995
Asset Retirement Liability		(15,289,994	)
Accounts Payable		(2,230,057	)
Cash paid at closing		(2,250,000	)
FV of Equity Issued		(2,071,657	)
Pre-tax Gain	$	458,712,296
Deferred taxes		(184,703,207	)
Net Gain	$	274,009,089

The gain of $274,821,626 disclosed in the footnote was not the actual gain recorded, which was $274,009,089. The $812,537 difference relates to closing costs recorded, but not accurately disclosed in the footnote. We will modify the footnote presentation in future filings.


	·	The calculation of $184,703,207 Deferred Income Tax Payable is as follows:


Pre-tax Gain	$	458,712,296
Deferred Federal tax at 35%		160,549,304
Deferred state tax, net of federal benefits		24,153,903
Total Deferred Taxes	$	184,703,207

We note as a result of accounting records not being maintained on an adequate basis to carve out historical operational results on the specified acquired assets, the resulting assets and liabilities were deemed not to have been a separate business for purposes of preparing pro forma financials with historical results for the past year or a related stub period. Please provide more analysis on your conclusion this acquisition was not a separate business and should be accounted as an asset acquisition. Tell us specifically how long the oil and gas producing assets were not operational prior to acquisition and the period of time accounting records were not maintained. We note in addition to the oil and gas properties, a significant amount of onshore and offshore production facilities were also acquired. Tell us in more detail what is included in the fixed assets acquired in the amount of $110,516,500.

RESPONSE:

As we disclosed on page 39 (Recent Accounting Pronouncements) of the April 30, 2010 Form 10-K, we accounted for each of our fiscal 2010 acquisitions, including CIE, as business combinations, and applied the provisions of ASC Topic 805-20. We acknowledge that our description of the transaction in footnote 6 is confusing due to the fact that we described the transaction as an “acquisition of certain assets,” and will clarify this in future filings.

In November 2009, the Company acquired the Alaska assets from a bankruptcy proceeding whereby certain assets of Pacific Energy were permitted by the bankruptcy court to be sold in pieces. The Pacific Energy estate had been abandoned as of September 10, 2009. The Pacific Energy administrative staff, including the accounting personnel and its offices had largely been dismantled by the time the Company had began its due diligence in late October 2009. In December 2009, we had a telephone conversation with the former Chief Financial Officer of Pacific Energy, who informed us that his accounting systems were no longer operational, could not be accessed and that he would not be able to provide any historical accounting records for the acquired assets. He did not elaborate on the length of time Pacific Energy’s accounting systems were not operational, and it was clear that he was not going to provide assistance in obtaining historical financial information. We do not know for certain how long accounting records were not maintained, however, based on our due diligence procedures we estimate that there was at least a four month period where no financial records were maintained.

The operations on the Alaska oil and gas wells had ceased production by August 31, 2009 and had not been fully operational for months according to the limited information provided to us during our due diligence. We subsequently determined that several of the wells, which were operational for a period of time with Pacific Energy, had become inoperable as the well casings had collapsed and would require rework. In addition, our Osprey offshore drilling platform (“Osprey Platform”) ceased production in July 2009 and was inoperative, as its oil wells all had failed pumps and/or casing problems which required a workover or drilling rig to repair, and the drilling rig had been removed from the Osprey Platform. As a result, none of the oil wells supported by the offshore drilling platform could resume production without the substantial investment required to refurbish the Osprey Platform and its pipelines with a drilling rig.

Although the Company acquired some $110 million of fixed assets, the majority of these assets were idle even when Pacific Energy was operational. Over seventy percent (70%) of such assets were attributed to the Osprey Platform, its pipelines, and the associated Kustatan Production Facility. Kustatan was built to provide the Osprey Platform with electrical power and processes the production fluid received from the Osprey Platform into salable oil and gas. Fixed assets purchased consisted of the following:


Kustatan Production Facility	$	60,000,000
West McArthur River Production Facility		23,000,000
West Foreland Gas Pad & Dehydration Facility		2,000,000
Redoubt pipelines		11,390,000
Pipelines – West McArthur River		5,610,000
Osprey Platform		6,000,000
West McArthur River Camp Facility		2,000,000
Vehicles, machinery & equipment		516,500
Total	$	110,516,500

Due to these extenuating circumstances and the lack of accounting records and the nature of the assets acquired, pro forma financial disclosures under ASC Topic 820 could not be included in the financial statements. However, the usefulness of such pro forma information would have been limited given the time period these assets were not operational.

Note 7. Derivative Liabilities, page F-16

We note you have recorded non-cash losses of $15,861,006 relating to the change in fair value of your derivative instruments. Please tell us in more detail how this loss was calculated and your accounting for your warrants with reset provisions under ASC Topic 815. Please provide more analysis on how you determined the fair value of the warrants issued and outstanding at May 1, 2009 attributed to your derivative liability was immaterial.

RESPONSE:

The components of the derivative liability recorded as of April 30, 2010 of $17,429,787 and related expense recorded during the year of $15,861,006 are comprised of three different transactions. We have detailed these transactions in a table to facilitate the understanding of the different components.


Transaction	Number of warrants		Value at April 30, 2009		Additional Paid in Capital		Expense		Value at April 30, 2010
Petro / Prospect		3,000,000	$	389,852	$	-	$	15,242,309	$	15,632,141
March 2010 Financing		716,715		-		542,094		178,746		720,840
Consulting Agr		300,000		-		636,835		439,951		1,076,786
Total		4,016,715	$	389,852	$	1,178,929	$	15,861,006	$	17,429,787

Current portion									$	720,840
Long term portion										16,708,947
Total derivative liability									$	17,429,787

The Company had one existing arrangement which had warrants with ratchet down provisions and then entered into two more arrangements with warrants containing ratchet down provisions in March 2010. The accounting related to the warrants with ratchet down provisions for the original Petro / Prospect arrangement was covered by the accounting guidance of EITF 07-5 as subsequently codified as ASC Topic 815, which was adopted by the Company on May 1, 2009. The initial accounting for these warrants issued periodically over the years was to record the fair value of the instruments as a component of equity. Upon the adoption of ASC Topic 815, these warrants were no longer afforded equity treatment, but instead were required to be recorded as a liability. We made an evaluation on May 1, 2009 of the fair value of these warrants utilizing the Black Scholes option pricing model which had an exercise price of $1.15, a market price of the stock on May 1, 2009 of $0.34 and a volatility factor of 110%, resulting in a value of $389,582. We reclassified this amount from equity (additional paid in capital) to a liability in the then current year ended April 30, 2010, as such amount we deemed to be immaterial for the current year of activity. We also viewed this amount as immaterial to the April 30, 2009 balances, and as such did not deem it appropriate to restate those balances as afforded by the accounting guidance for the adoption this provision of ASC Topic 815.

At April 30, 2010, we utilized the Black Scholes option pricing model to fair value the ratchet down provisions of the warrants for computing the changes in valuations during the year. The year end assumptions utilized the current market stock price of $5.78, exercise prices of the different warrants issued, volatility of 49% for the newly issued warrants and 140% for the Petro / Prospect warrants and terms of 0.42 for the March 2010 financing warrants and 2.5 years for the consulting agreement and Petro / Prospect warrants.

The valuation of the derivative nature of the Petro / Prospect warrants was actually complicated by negotiations and ultimately litigation in a case initiated in March 2010, as to viability or merits of even the need to have issued such warrants or any number of warrants subject to some penalty provisions of an old repaid financing arrangement. The Petro / Prospect negotiations had escalated in the year ended April 30, 2009. This negotiation grew into a litigation matter after the Company acquired the Alaska assets and was ultimately settled separately for Petro in October 2010 for the issuance of 518,510 shares of stock and Prospect in December 2010 for the issuance of 2,013,814 shares of stock. These settlements with Petro / Prospect also cancelled all of the Petro / Prospect warrants in dispute. The market value of the shares issued to Petro / Prospect approximated the recorded derivative liability of Petro / Prospect warrants.

Note 14. ASC 932-S50 Extractive Activities – Oil and Gas Disclosures, page F-26

We note your standardized measure of discounted future net cash flows at April 30, 2010 in the amount of $230 million. We also note your oil and gas properties at April 30, 2010 in the amount of $376 million. Tell us your consideration of your standardized measure in the impairment analysis for your oil and gas properties. Please be specific in your response and provide analysis why your standardized measure at April 30, 2010 would not be an indication of impairment for your oil and gas properties.

RESPONSE:

The Company assesses its proved oil and gas properties for impairment under ASC Subtopic 360-10-35. Under ASC Subtopic 360-10-35, assuming a triggering event was deemed to have occurred, the first step of an impairment test would be conducted using undiscounted estimated future pre-tax cash flows which would incorporate the forward price strips for oil and natural gas and cost escalations. If the book basis of our properties were to exceed this undiscounted cash flow amount, a second step of the impairment test would be triggered which would compare the book basis of our properties to the discounted cash flows in order to calculate the amount of an impairment. The book basis of our properties has not exceeded the undiscounted estimated future cash flows, so the first step of the impairment test has not indicated the need for impairment.

The standardized measure represents discounted (PV-10) after-tax cash flows calculated using average fiscal year pricing and prevailing cost conditions. As such, the standardized measure is not indicative of the fair value of our proved oil and gas properties, nor would use of such measure be consistent with application of ASC 360-10-35.

Form 10-Q for Fiscal Quarter Ended October 31, 2010

Note 2. Accounting Policies

Principles of Consolidation and Non-Controlling Interest, page 10

We note your consolidated financial statements include the amounts of the Company and its subsidiaries, all of which are wholly-owned at October 31, 2010 except for Miller Energy Income, 2009-A, LP (“MEI”), which is controlled by the Company. This disclosure regarding your consolidation policy with MEI is not clear. Please revise your disclosure to clarify your consolidation policy with MEI and tell us in more detail about your non-controlling interests and how you are accounting for them.

RESPONSE:

MEI is a limited partnership owned by several partners. The General Partner to the entity is Miller Energy GP, LLC which is 100% owned by the Company and the officers of Miller Energy GP, LLC are also officers of the Company.

MEI was formed to generate investment capital, which would be invested in oil and gas producing assets or loaned against oil and gas producing assets. The Company and its officers manage these assets on behalf of MEI. The funds raised to date had been loaned solely to the Company. MEI currently has no new fund raising efforts being executed or planned.

We evaluated the consolidation of MEI as a variable interest entity based on FASB guidance of ASC Topic 810, which requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has all of the following characteristics:


1.	The power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance,


2.	The obligation to absorb losses of the entity that could potentially be significant to the variable interest entity, and


3.	The right to receive benefits from the entity that could potentially be significant to the variable interest entity.

Additionally, an enterprise is required to assess whether it has an implicit financial responsibility to ensure that a variable interest entity operates as designed when determining whether it has the power to direct the activities of the variable interest entity that most significantly impact the entity’s economic performance.

The following facts were considered when determining consolidation of MEI as a variable interest entity:


-	MEI raised funds through several investors, and subsequently loaned the proceeds to the Company. The loan receivable as the sole asset of MEI is recorded as a loan payable by the Company and is collateralized by certain equipment assets of the Company.

The Company issued 1,329,250 shares of common stock and 1,329,350 warrants to purchase common shares at an exercise price of a $1.00 to the investors of MEI as an inducement to invest. These common shares and warrants issued had a fair value of $1,048,765, which were recorded as a debt discount by the Company and are being amortized over 48 months; the term of such debt with MEI. In addition the Company incurred $619,358 of finance costs of professional fees and commissions paid to raise such monies for MEI. These amounts are being amortized as deferred financing costs over 48 months.


-	The General Partner to MEI is Miller Energy GP, LLC which is 100% owned by the Company and the officers of Miller Energy GP, LLC are also officers of the Company, so the Company does have the ability to exercise control over MEI.


-	The Company pays interest on this loan monthly on a 12% per annum basis which matures in 2013.


-	The sole asset of MEI is the loan receivable due from the Company and the sole source of cash flow inflows are funded via the debt service payments received from the Company, which are distributed directly to the investors of MEI on a pass through basis, monthly.


-	MEI has no further intentions to raise additional investment or provide any new loans or investments in the oil and gas industry.


-	Two of the conditions to be evaluated for ASC Topic 810 are losses to be absorbed and future benefits. MEI has no new investments to loan; therefore there is no further economic benefit to be obtained from MEI. Also, there are no material additional expenses of MEI expected that the Company would have to absorb.

Based on our evaluation, the Company has not consolidated MEI, even though the Company controls MEI, by virtue of common management. The Company has already recorded the full current and future economic impact of MEI, without the consolidation of MEI by virtue of the simple financing structure and disclosed required commitments for future payments. The primary difference on our balance sheet if MEI was consolidated is not material, and would consist of a reclass from a non-current liability classification of Notes payable – related parties, net to a component of Equity. In addition, there are no further losses of MEI to be absorbed or incurred, since the Company has recorded the financing structure and disclosed its terms. The Company has disclosed the future required payments due to MEI in our Long Term Debt footnote number 8 to the financials included in the April 30, 2010 Form 10-K.

In future filings, we will record MEI on a consolidated basis and will reclassify prior period amounts in future filings as well. We will also clarify our consolidation policy in future filings.

Engineering Comments

Form 10-K for Fiscal Year Ended April 30, 2010

Business, page 1

Assignment Oversight Agreement, page 3

10.

We note you estimate that the agreement with Alaska DNR obligates you to $35 million in capital funding commitments, you will need up to approximately $67.4 million (page 29) associated with obligations arising from your purchase of the Alaskan assets, and your third party reserve report presents $50 million in proved property development costs. With reasonable detail, please explain to us the differences in these three figures and tell us the status of your efforts to obtain funding for these obligations. Please note that the operational and financial capability to execute development is a necessary criterion for attribution of proved undeveloped reserves.

RESPONSE:

By way of background, on November 5, 2009, CIE entered into an Assignment Oversight Agreement with the Alaska DNR. The agreement also required CIE to demonstrate funding commitments to support restoration of the base production at the onshore locations of $5 million and offshore platform of $31 million, which was done prior to the acquisition of the assets. We still have development commitments embedded in our Plans of Development filed with the DNR, but these do not have precise dollar amounts associated with them. The Company estimated at the time that $35 million would be necessary to execute our plans to establish base production from the Redoubt Unit. The $50 million figure used by Ralph E. Davis Associates, Inc. in the reserve report included development costs for proved property development costs; the $35 million was an estimate for Redoubt Unit development costs only.

There is an additional obligation to establish an escrow account to provide for the dismantlement of the onshore and offshore assets. At the time we were in ongoing discussions with the DNR about the appropriate amount of funding necessary, and believed the maximum obligation would be $10 million to fund our onshore abandonment obligation and $29 million to fund our offshore abandonment obligation, less $6.6 million in funding that had been escrowed by Forest Oil and Pacific Energy to which CIE would be able to take title, for a total of $32.4 million. The $67.4 million figure included the $35 million in estimated development funding, plus the estimated $32.4 million for asset retirement obligations. Since that time we have reached a final agreement with the DNR regarding abandonment funding, which will be $10 million less than was assumed at the time.

At the date of acquisition, when proved undeveloped reserves were identified, the Company was in the process of raising additional capital and within approximately 3 months had raised $11.8 million for development. Since then, the Company has been pursuing further efforts to obtain financing. On March 2, 2011, a $5,000,000 line of credit maturing on February 21, 2011 was extended to April 21, 2011 and extended again to July 5, 2011 to us by a bank. We entered into the short-term facility to provide capital to us for the continued development of our Alaskan operations while we negotiated a larger, permanent facility. In addition, we have attended numerous investor meetings and have had discussions with banking firms, brokers and lending individuals. The Company recently received a non-binding lending term sheet from a potential lender detailing terms to provide debt financing to the Company to be able to fund these obligations. At the date of this filing we are negotiating the terms of the agreement and have not yet closed on the transaction.

Net Reserves at April 30, page 4


11.	We note the presentation of your Alaska net reserves here and in Exhibit 99.1. Please submit to us the petroleum engineering reports – in hard copy and electronic spreadsheet format – you used as the basis for your 2010 Alaska reserve disclosures. The report should include:


a)	Total company summary income forecast schedules for proved, probable, and possible reserve categories with proved developed segregated into producing and non-producing properties;
b)	Individual income forecasts for each of the 43 properties included in Exhibit 99.1;
c)	Engineering exhibits (e.g., maps, rate/time plots, volumetric calculations, analogy well performance) with narratives for each of the five largest leases (PV10 basis), and;
d)	Base maps for each filed that identify existing well and PUD locations as well as producing status.

You may contact us for assistance in this or any other matter.

RESPONSE:

Supplementally we are providing the requested data.


12.	We note the inclusion of Alaska proved gas reserves with the $4.84/MCF gas price (page 6) despite the statement on page 10 that all natural gas produced by Cook Inlet Energy was used by it to generate heat and power at its production facilities. Please explain this situation to us. Address the support for reasonable certainty of future gas sales.

RESPONSE:

Since acquisition, the Company’s produced gas has been used to provide power to our oil production facilities. None of that gas was sold to third parties. In the future, the Company anticipates selling the gas to local utilities. The Company has been approached by a local utility about buying existing gas. Once the Company has excess production as a result of building additional wells, we reasonably expect to begin selling excess gas to local utilities.

There is a ready market for natural gas, as there is a shortage of natural gas in the Cook Inlet region of Alaska. Alaska is currently looking for ways to supplement this shortage and predicts a rise in gas prices over the near term. Also, if the current trends for well success rates and costs continue, producers will need to spend two to three times current amounts, or an estimated $1.9 to $2.8 billion, to meet projected Cook Inlet utility demand between now and 2020. Here is a link to an informative study, entitled “Cook Inlet Gas Study – An Analysis for Meeting the Natural Gas Need of Cook Inlet Utility Customers” by Petrotechnical Resources of Alaska in March 2010. [http://www.petroak.com/pdf/CI_Gas_prareport.pdf]

13.

We note the adjusted oil price (about $64/barrel, Exhibit 99.1, page 4) applied to the Alaska net proved oil reserves (10,230 MBO) yields net sales of about $655 million which is basically the same as the total revenue attributed to net proved oil and gas reserves (Exhibit 99.1, page 2). Please explain this apparent inconsistency to us. Address whether these gas reserve volumes are lease fuel and, if so, illustrate, with reasonable detail, your treatment of them in the standardized measure.

RESPONSE:

The gas reserve volumes were not lease fuel. Per the initial Ralph E. Davis Associates, Inc. reserve report as of December 10, 2010, the date of acquisition, the crude oil prices used were based on a WTI price of $61.18 per barrel and held constant for the length of each contract. As of April 30, 2010 this price had risen $11.83 per barrel to $73.01 per barrel. In addition, the $61.18 price was adjusted as follows:

1. Add $0.995 for non-Redoubt crude.

2. Less $0.45 for Redoubt crude.

3. Less an estimated ANS (Alaska North Slope crude) discount of $2.00/bbl.

4. Less a “CISPRI allowance” (a spill response cooperative) of $0.72/bbl in 2009 escalated at 5% annually.

5. Less a shipping charge of $1.184/bbl in 2009 escalated at 5% annually.

6. Less a pipeline tariff of $4.08/bbl.

The adjustments outlined above were inserted in the pricing file as price adjustments; therefore the effective oil price averaging $51.365 per barrel resulted. Because of the contractual escalation in “CISPRI allowance” (spill response cooperative) and the shipping charge this effective average price decreases in subsequent years.


14.	Please expand your disclosure to describe the items of uncertainty that characterize your disclosed unproved reserves. Refer to Item 1202(a)(5) of Regulation S-K.

RESPONSE:

We will expand our disclosure in future filings to describe the items of uncertainty that characterize our disclosed unproved reserves as follows:

Unproven reserves are based on geological and/or engineering data similar to that used in estimates of proven reserves, but technical, contractual, or regulatory uncertainties preclude such reserves being classified as proven. They are sub-classified as probable and possible.

Probable reserves are attributed to known accumulations and usually claim a 50% confidence level of recovery. Possible reserves are attributed to known accumulations that have a less likely chance of being recovered than probable reserves. This term is often used for reserves which are claimed to have at least a 10% certainty of being produced. Reasons for classifying reserves as possible include varying interpretations of geology, reserves not producible at commercial rates, uncertainty due to reserve infill (seepage from adjacent areas) and projected reserves based on future recovery methods.

Appalachian Region, page 4


15.	Please correct your statement on page 5, “When used in this table, MBbls means million barrels of oil…” as the context of your presentation “MBbls” are thousands of barrels.

RESPONSE:

We will revise our disclosure in future filings to correctly reflect that Mbls means thousands of barrels of oil.

16.

We note your statement, “Both of these reserve reports which are filed as exhibits to this annual report, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles….” While we understand that there are fundamentals of physics, mathematics and economics that are applied in the estimation of reserves, we are not aware of an official industry compilation of such “generally accepted petroleum engineering and evaluation principles.” With a view toward possible disclosure, please explain to us the basis for concluding that such principles have been sufficiently established so as to judge that the reserve information has been prepared in conformity with such principles. Refer us to a compilation (rather than a citation or reference) of these principles.

RESPONSE: Our statement that our reserve reports were prepared “in accordance with the generally accepted petroleum engineering and evaluation principles…” was not intended to imply that an official industry compilation exists. Rather, this statement reflects our understanding that our independent engineering firms prepared our reserve reports with due professional care and in compliance with the SEC definitions and guidance and therefore are comparable to other reserve reports in the industry. In future filings, we will revise our disclosure as follows:

Our reserve reports were prepared using engineering and geological methods widely accepted in the industry. All reserve definitions comply with the applicable definitions of the rules of the SEC. The accuracy of the reserve estimates is dependent upon the quality of available data and upon independent geological and engineering interpretation of that data. For the proved developed producing, the estimates were made when considered to be definitive, using performance methods that utilize extrapolations of various historical data including, but not limited to, oil, gas and water production and pressure history. For the other proved producing, proved behind pipe reserves, proved undeveloped reserves, and probable and possible reserves estimates were made using volumetric methods.

17.

We note the statement, “Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent engineering firm under the supervision of our Chief Financial Officer.” Please expand this to disclose the qualifications of your CFO in this regard. Refer to Item 1202(a)(7) of Regulation S-K.

RESPONSE:

Our internal controls with regard to our reserves estimations oversight consist of interviews with the independent petroleum engineering firms, preparation and submission of material such as production pricing and costs, expectations of reserves based on changes in pricing, additions or reductions of leases, changes in well performance and comparative analysis to former reports. We did not mean to suggest that our CFO was qualified as an engineer, but just that he was the person in our Company who monitored our internal controls in the manner just described. In future filings, we will revise our disclosure as follows:

Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent engineering firm. Our Chief Financial Officer and our Chief Executive Officer in Alaska are primarily responsible for the engagement and oversight of our independent engineering firm. We provide the engineering firm with estimate preparation material such as property interests, production, current operation costs, current production prices and other information. This information is reviewed by our Chief Executive Officer in Alaska and our Chief Financial Officer prior to submission to our third party engineering firm. A letter which identifies the professional qualifications of each of the independent engineering firms who prepared the reserve reports are included in those reserve reports which are filed as exhibits to this annual report.


18.	You state that the professional qualifications of each of the independent engineering firms who prepared the reserve reports are included in those reserve reports which are filed as exhibits to this annual report. These appear to have been omitted. Please furnish to us reports updated to include this information.

RESPONSE:

Included as Exhibits 1 and 2 to this response are reserve reports from each of LKA and Ralph E. Davis Associates, Inc. which include the professional qualifications of each of these independent firms.

Drilling Activities, page 9


19.	We note the $5.8 million of development cost incurred during the fiscal year ended April 30, 2010 (page F-26) as well as the statement that you are focused on the reworking of Cook Inlet wells. Please expand this to explain with reasonable detail the results of this expenditure. Refer to Item 1205(c) of Regulation S-K.

RESPONSE:

We will expand the disclosure in our future filings as follows:

The Company incurred $5.8 million of development cost in the Cook Inlet region. These costs were primarily related to recompletion and repair of wells that were shut in by Pacific Energy, as well as repair of the physical infrastructure. Three oil wells and four gas wells were producing in Cook Inlet by April 30, 2010.

Principal markets and principal customers, page 10


20.	We note the tabular presentation of historical oil production, oil prices, and unit production costs. Please explain to us the omission of Appalachian gas sales volumes, prices and unit costs and expand this disclosure to comply with Item 1204 of Regulation S-K.

RESPONSE:

It appears that we inadvertently omitted the Appalachian gas sales volumes, prices and unit costs. The revised table and disclosure follows, which we will include in our Form 10-K for the fiscal year ended April 30, 2011:

The following table presents information regarding production volumes and revenues, average sales prices and costs, after deducting royalties and interests of others, with respect to oil and gas production attributable to our interest for the last three years. Average production cost are costs incurred to operate and maintain the wells and equipment and to pay the production costs, which does not include ad valoreum and severance taxes per unit of production, and is exclusive of work-over costs.


	Year Ended April 30,
	2010		2009		2008
Oil production (Bbls)
Cook Inlet
Production		46,445		—		—
Average sales price	$	78.76		—		—
Average production cost	$	43.54		—		—
Appalachian region
Production		2,945		4,580		4,984
Average sales price	$	71.33	$	68.77	$	77.25
Average production cost	$	54.64	$	52.49	$	21.73

Gas production (mcf)
Cook Inlet
Production		37,311		—		—
Average sales price*		—		—		—
Average production cost*		—		—		—
Appalachian region
Production		74,532		50,073		39,507
Average sales price	$	3.96	$	8.00	$	7.39
Average production cost	$	6.52	$	4.14	$	5.55


* All gas produced for the year-ended April 30, 2010 was used for power generation for the oil production. As such, it was not sold and its cost is included in oil production costs.


21.	We note that your Alaskan operations are subject to pipeline tariffs of $14.57/BO and royalties from 4% to 12.5%. Please explain to us on an itemized basis how these deductions are included in your 3rd party reserve report (e.g., increased cost, decreased entitlement).

RESPONSE:

All deductions for pipeline tariffs are taken out of the calculation of pricing for Crude Oil. Ralph E. Davis Associates, Inc. used $4.08 per barrel for tariffs in calculating net revenue. Please see page 4 of the attached Ralph E. Davis Associates, Inc. report. At the time of its report, the news of a tariff increase had been mentioned publicly, but its finality was not certain. . The Company was required to pay this amount and did so under protest, but did not believe there was a reasonable basis to raise this tariff to $14.57, an increase of over 250%, and therefore immediately filed an appeal with the Regulatory Commission of Alaska during the time period Ralph E. Davis Associates, Inc. was estimating this rate. Due to the appeal and the unlikelihood of the new tariff remaining, Ralph E. Davis Associates, Inc. used the previous tariff of $4.08.

On November 19, 2010, the Regulatory Commission of Alaska accepted a settlement agreement between CIE and CIPL. This settlement, as reported on a Current Report on Form 8-K as filed on November 26, 2010, reduced transportation costs for all CIE production by $6.57 per barrel to a rate of $8.00 per barrel for the remainder of 2010. On February 17, 2011, the Company received approximately $1.5 million from CIPL as its 2010 true-up payment. The settlement also laid out a methodology for determining CIE's future pipeline transportation rates. The rates to be

paid by CIE to CIPL during calendar years 2011 through 2014 shall be determined by dividing the agreed annual CIPL revenue requirement of $17.28 million for each year of the term of the Settlement Agreement by the forecasted total annual CIPL throughput. CIE has committed to pay for transportation of a minimum of 260,063 barrels of production in 2010 and 346,750 barrels in each of the years 2011 through 2014. Each February, a true-up adjustment for the previous year will be made by dividing the $17.28 million revenue requirement of the pipeline by the actual number of barrels put through the line by all shippers to determine the rate due to CIPL. After the rate due to CIPL is determined in accordance with the true-up terms, any overpayment by CIE up to $250,000 will be credited against future shipments, and any amount above $250,000 shall be repaid to CIE in cash. In the event that CIE had underpaid CIPL for the previous year, payment of that shortfall would be made after the annual true up. On February 15, 2011, we received a cash payment of approximately $1,500,000 pursuant to the true-up. CIPL retained another $250,000 that was credited against our shipping cost.

Royalty and NRI is the difference between the Gross Oil and Gas columns and the Net Oil and Gas columns on the attached Ralph E. Davis Associates, Inc. report.

Consolidated Financial Statements

Notes to the Consolidated Financial Statements, page F-8

Reserve Quantity Information, page F-29

22.

The estimated future unit production cost (with taxes) in the 2010 standardized measure is about $11/BOE (=$123.5 million/11254 MBOE) while your disclosed 2010 historical unit production cost for Alaska (page 10) is $43.54/Barrel. The Results of Operations (page F-26) presents the 2010 production cost as $96,240 which yields a unit cost of 68¢/BOE. Production costs are described in Rule 4-10(a)(17) of Regulation S-X and FASB ASC 932 paragraph 932-235-50-26. With reasonable detail, please reconcile the differences among these three figures to us and comply with Rule 4-10 and ASC 932.

RESPONSE:

The Company incorrectly reported 2010 production costs at $96,240. The actual production costs of $4,324,533 or $30.56/BOE, are broken out as follows:


Labor			730,941
Repairs			49,629
Supplies & Materials			1,802,814
DD&A			1,741,150
			4,324,533

Additionally, the Company incorrectly reported the third quarter Average Production Cost of $43.54 for Alaska. The annualized Average Production Cost should have been noted as $32.83 for the year ended April 30, 2010.

This does, however, leave an approximate difference of $19/BOE to $21/BOE when comparing to the $11.00/BOE. Our actual costs for the period included workover expenses with the recently purchased wells that are not included in future net revenues. Those costs would increase our initial annual production costs per barrel, while we believe subsequent years production costs would more closely approximate the estimated future unit production cost of approximately $11.00 per BOE. Additionally, the reserve reports, as noted above, used $4.08 per barrel for tariffs. Actual tariffs during this period were $14.57 per BOE, or $10.49 more per BOE. The remaining variance is attributable to royalty and NRI reductions. We will correct this information in future filings.

Exhibit 99.1


23.	We note that certain information per Item 1202(a)(8) of Regulation S-K has been omitted from this third party reserve report. Please procure a third party reserve report that includes:


	·	The purpose for which the report was prepared and for whom it was prepared;
	·	The date on which the report was completed;
	·	A discussion of the possible effects of regulation on the ability of the registrant to recover the estimated reserves, and;
	·	A statement that the third party has used all methods and procedures as it considered necessary under the circumstances to prepare the report;

RESPONSE:

Included as Exhibit 1 to this response is a revised discussion letter to the reserve report from Ralph E. Davis Associates, Inc. which includes the requested additional information.

Exhibit 99.2


24.	We note that certain information per the noted sections of Item 1202(a)(8) of Regulation S-K have been omitted from this third party reserve report. Please procure a third party reserve report that includes:


	·	The purpose for which the report was prepared and for whom it was prepared;
	·	The date on which the report was completed;
	·	The proportion of the registrant’s total reserves covered by the report;
	·	A discussion of primary economic assumptions including average benchmark prices and average adjusted prices used to estimate reserves;
	·	A discussion of the possible effects of regulation on the ability of the registrant to recover the estimated reserves, and;
	·	A statement that the third party has used all methods and procedures as it considered necessary under the circumstances to prepare the report;
	·	A brief summary of the third party’s conclusions with respect to the reserves estimates, and;
	·	The signature of the third party.

RESPONSE:

Included as Exhibit 2 to this response is a revised discussion letter to the reserve report from Lee Keeling and Associates, Inc. which includes the requested additional information.

The Company acknowledges that:


	·	the Company is responsible for the adequacy and accuracy of the disclosure in their filings;


	·	staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and


	·	the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

The Company trusts the foregoing sufficiently responds to the staff’s comments.