 | John M. Brawley |
| Chief Financial Officer | |
| Miller Energy Resources, Inc. | |
| 9721 Cogdill Road, Suite 302 | |
| Knoxville, TN 37932 | |
| Direct Dial: (713) 882-6812 | |
| Office: (865) 223-6575 | |
| Fax: (865) 691-8209 | |
| jbrawley@millerenergyresources.com | |
April 11, 2014
Mr. Ethan Horowitz
Branch Chief
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549-3561
Re: Miller Energy Resources, Inc.
Form 10-K for Fiscal Year Ended April 30, 2013
Filed July 15, 2013
File No. 001-34732
Ladies and Gentlemen:
Set forth below are the responses of Miller Energy Resources, Inc. (the “Company”, “we,” “us” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated February 21, 2014, with respect to Form 10-K for Fiscal Year Ended April 30, 2013, File No. 001-34732, filed with the Commission on July 15, 2013 (the “Form 10-K”).
For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text. All references to page numbers and captions correspond to the Form 10‑K for Fiscal Year Ended April 30, 2013 unless otherwise specified.
With the Staff’s permission, where the responses indicate that the Company will revise its disclosures and/or make additional disclosures, the Company requests permission to include such disclosures in its future filings of the type to which the comment relates.
Form 10-K for Fiscal Year Ended April 30, 2013
Business and Properties, page 1
Cook Inlet and Susitna Basins, page 2
| 1. | You state on page 3 of your Form 10-K, “In its 2011 Assessment of Undiscovered Oil and Gas Resources of the Cook Inlet Region, the United States Geologic Survey (“USGS”) estimated mean undiscovered technically recoverable reserves of 599 million bbls of oil and 19 tcf of natural gas. All of the undiscovered oil and 13.7 tcf of the undiscovered gas are conventional resources, and 5.3 tcf of natural gas was estimated to be technically recoverable as coal bed methane. This report considered the full oil and gas potential of the Cook Inlet Basin, but only the coal-bed methane potential of the Susitna Basin. These numbers do not include oil and gas remaining to be produced in currently producing fields.” The Instruction to Item 1202 |
of Regulation S-K generally prohibits the disclosure of “Estimates of oil or gas resources other than reserves, and any estimated values of such resources….” Please remove this paragraph and any similar disclosures from your filing.
RESPONSE:
The citation of the publicly released USGS report was only intended to familiarize investors with the oil and natural gas prospectivity of the Cook Inlet Region. We respectfully submit that such estimates could not be reasonably inferred to assign quantities of reserves or value to the limited interests of the Company in the Cook Inlet Region. Nevertheless, in future filings with the Commission, we will remove quantifications of reserves that do not meet Commission definitions from any such reference to the USGS report on the Cook Inlet Region.
| 2. | You disclose that in March 2011, you replaced the electrical submersible pump (“ESP”) in two Redoubt Unit wells. Please tell us the costs associated with these activities and explain whether you have made similar repair/replacement since March 2011 or anticipate such activities in the future for any of the other Cook Inlet oil wells. |
RESPONSE:
In March 2011, work commenced to restart operations on the Osprey platform and to bring previously producing wells online, each of which required a work-over to be returned to production. The successive ESP replacements were largely related to the continuing cleanup of the previously producing wells. The ESP units used by the Company in Alaska range in cost from $500,000 to $800,000. In order to restore production on the RU-1 well, the ESP on that well was first replaced in May 2011 at a cost of approximately $645,000 for the physical pump. Shortly thereafter, the ESP on the RU-7 well was replaced at a similar pump cost as part of the work to restore production. During this period, the Company spent approximately $2.3 million, which included ESP replacement costs and mobilization and related costs for a snubbing unit used on the Osprey platform for the initial multi-well restart and initial downhole cleanup work. The replaced ESP on the RU-1well failed in September 2011 due in part to downhole well contamination and wellbore integrity issues that could not be accessed and removed with the snubbing unit. After the new and more powerful rig was deployed on the Osprey platform in August 2012, the RU-7 well was subsequently reworked to remove well contamination in connection with an overall well workover and the ESP on that well was again replaced at a pump cost of approximately $675,000. The RU-1 ESP was again replaced in the fall of 2012 and the well was eventually sidetracked in early 2013.
While these pumps can last the life of a well, we believe our experience with these replacements was largely attributable to the well cleanup and wellbore integrity issues that was required in order to get the wells fully and efficiently producing. Also, in certain instances the Company may decide as part of its overall optimization decisions with respect to workover activities to replace the ESP with a more efficient or better suited design or to reduce the risk of future failure. The Ralph E. Davis Associates, Inc. (“Davis”) reserve report filed as part of the Form 10-K does not include the cost of future replacement of ESPs because such pump failures or replacements are not routinely expected or predictable and production optimization workovers have not been scheduled in the reserve report.
Appalachian Region, page 5
| 3. | We note that you have disclosed only proved producing Tennessee reserves as well as your statement, “Miller has millions of cubic feet of gas shut-in and behind pipe in Tennessee. With the price of natural gas moving upward, we plan on moving forward to secure markets for this gas.” As this statement does not appear to be supported by your disclosure of non-producing reserves, please advise or remove this and any other similar statements from your filing. |
RESPONSE:
While the Company believes it has the potential to restore numerous previously producing wells in Tennessee to economic producibility, the Company will eliminate in future filings any reference to quantities of such reserves
until a development plan has been adopted and an appropriate reserve estimate has been made in compliance with Commission definitions and rules.
Production, Pricing, and Lease Operating Cost Data, page 8
| 4. | Item 1204 of Regulation S-K requires the disclosure by geographical area of “…production, by final product sold, of oil, gas, and other products.” You have presented only barrel of oil equivalent volumes that appear to combine results from Alaska and Tennessee and appear to include figures for fuel gas (footnote 1) as well as sales gas (from page 36). Please comply with Regulation S-K here or provide a cross reference to Alaska and to companywide total figures for production history, historical oil and gas sales volumes and product prices provided in Management’s Discussion and Analysis (pages 36-38 in this filing). |
RESPONSE:
The Company respectfully submits that information furnished by geographical area under Subpart 1200 of Regulation S-K is by “geographical area” as defined in Item 1201(d) of Regulation S-K, which is only required to be furnished at the country-by-country level. For this purpose, all of the Company’s oil and gas properties are located within the single geographic area of the United States. The additional information regarding the Company’s properties and operations in the two operating areas within its single geographic area has been provided because the Company believes it would be informative.
The Company acknowledges the comment regarding the treatment of fuel gas in disclosing production in accordance with Regulation S-K Item 1204 and will comply in future filings by footnoting the fuel gas production volumes that have been excluded from sales volumes. We note that production volumes were disclosed excluding fuel gas on pages 1 and 36 of the Form 10-K.
| 5. | Item 1204 of Regulation S-K also specifies that the historical unit production costs be disclosed by geographic area. Please modify your disclosure here and/or in Management’s Discussion and Analysis to present this information separately for Alaska and in total. |
RESPONSE:
For the reasons stated in the response to Comment 4, the Company believes it has provided all information required by its single geographic area of the United States.
Oil and Natural Gas Reserves, page 10
| 6. | Please provide us with the petroleum engineering reports you used as the basis for your April 30, 2013 Alaskan proved reserves disclosures on page 11 and in Exhibit 99.1. You may furnish these materials on digital media such as flash drive or compact disk. |
The report should include:
a) One-line recaps in spread sheet format for each property sorted by field within each proved reserve category including the dates of first booking and estimated first production for your proved undeveloped properties;
b) Total company summary income forecast schedules for each proved reserve category with proved developed segregated into producing and non-producing properties;
c) Individual income forecasts for all the wells/locations in the proved developed and proved undeveloped categories;
d) Engineering exhibits (e.g., narratives, maps, rate/time plots, volumetric calculations, analogy well performance) for each of the three largest (by net oil reserves) wells/locations in the proved developed and
proved undeveloped categories (6 entities in all) as well as the AFE/capital cost inventory for each of the three PUD properties. Please ensure that the decline parameters, EURs and cumulative production figures are presented on the rate/time plots or other convenient location.
e) A line item comparison between the Cook Inlet production costs incurred in fiscal 2013 - $24.7 million on page F-29 - and those projected in your third party reserve report for fiscal 2014.
If you would like to have these supplemental materials returned to you, please comply with the provisions of Rule 418(b) of Regulation C, which provides for the return supplemental information as long as certain express conditions are met.
If you wish to request confidential treatment of those materials while they are in our possession, please follow the procedures set forth in Rule 83 of the Freedom of Information Act.
Please direct these engineering items to:
U.S. Securities and Exchange Commission
100 F Street NE
Washington, DC 20549-4628
Attn: Ronald M. Winfrey
RESPONSE:
The requested information has been furnished supplementally to Mr. Winfrey under separate cover letter dated April 1, 2014, which information is subject to a confidentiality request.
| 7. | You state on page 11 of your Form 10-K, “In fiscal 2013, we did not develop any PUDs.” Item 1203(d) of Regulation S-K requires explanation for the reasons that material amounts, if any, of proved undeveloped reserves remain undeveloped for five years or more after initial booking. Please expand this discussion to comply with Item 1203 of Regulation S-K. Also address the reasons that any PUD reserves are scheduled for development beyond five years after initial booking. You may refer to Rule 4-10(a)(31)(ii) of Regulation S-X. |
RESPONSE:
The Company has experienced delays in restoring production on our proved developed reserves in Alaska. As a result, we have been unable to make substantial progress on developing our proved undeveloped reserves. All of the Company’s proved undeveloped reserves estimated in the Davis reserve reports as of April 30, 2013 were scheduled for commencement of development on a date less than five years of the Company’s initial disclosure of its estimates of those reserves. In addressing the requirements of Item 1203 of Regulation S K, we note our discussion of the delays in initiating the Osprey platform operations, including the restoration of production of proved developed reserves which had obvious impact on our ability to commence development of proved undeveloped reserves, which is described in Form 10-K on page 1 under “Item 1 and 2. Business and Properties - Recent Developments - Drilling Activities” and on page 3 under “- Geographic Area Overview - Alaska Region - Osprey Platform and Redoubt Shoals Field.” In the current fiscal year, we have commenced or completed work on several wells that target reserves listed as proved undeveloped reserves in our reserve report dated April 30, 2013, including RU-2A, RU-5B (listed as “Redoubt 05A” in the report), WMRU-8 and RU-9 (listed as “Redoubt South Stepout 9” in the report).
In future filings on Form 10-K, we propose to address matters required under Item 1203 of Regulation S-K under a subheading labeled “Proved Undeveloped Reserves” proximately located to our total proved oil and natural gas reserves estimates. In this regard, the Company advises the Staff that it expects in its next annual report on Form 10-K that it may describe circumstances under which some of its proved development activities, including certain of its Redoubt Shoal field proved development activities drilled off of its Osprey harsh environment offshore platform, may be delayed beyond five years from the date of disclosure of initial reserves estimates. We respectfully submit that
the logistical and harsh weather environment circumstances in its Alaska operations and the evidence of continuous development by the Company give rise to specific circumstances under which proved reserves development may be scheduled to commence as of a date which more than five years from the date of disclosure of initial reserves estimates.
If such development activities are delayed beyond the five years, we expect to disclose in our future Form 10-K for the current fiscal year the specific circumstances related to such extended development, which may include some of the following facts. While the Company has been engaged in continuous development activities of the Redoubt Shoal field since it acquired the Redoubt Shoal field interests, the development projects can presently only be undertaken using the rig installed on the Osprey offshore platform, which due to infrastructure limitations can only work sequentially on drilling and development projects. The rig was installed in 2012 on the Osprey platform, was specifically designed for drilling, workovers and recompletions in the harsh offshore Alaska environment and is planned to be used for all of the Company’s wells and development projects accessing proved reserves in the Redoubt Shoal field. In addition to the logistics of developing sequentially with use of the rig, the Company experienced delivery and weather delays beyond its control in 2011 and 2012 in getting the rig installed and operational. In March 2011, work began to reactivate the once dormant Osprey platform and a drilling rig was contracted for modification to be installed on the platform. The construction, installation and final regulatory approvals of the rig on the Osprey platform were delayed until August 2012, in part due to a harsh prior winter.
We also note that in early 2013, the Company experienced a severe shortage of fuel gas and elected to complete two wells from the Osprey platform, the RU-3 and RU-4 wells, as gas wells principally to furnish fuel gas for the Company’s operations. RU-3 and RU-4 continue to be included in the Company’s proved undeveloped projects as oil recovery plays, collectively constituting approximately 29% of our total proved reserve volumes as of April 30, 2013. We expect to convert the RU-3 and RU-4 wells over to oil production after natural gas production from each of those wells depletes. The revised forecast depletion dates for natural gas accessed from those wells may be extended beyond the five year date applicable to the oil projects remaining for those wells.
Internal Controls over Reserves Estimate, page 11
| 8. | You state here “Our Chief Executive Officer of CIE and Acting Chief Financial Officer are primarily responsible for the engagement and oversight of our independent engineering firms.” Please expand this to disclose the qualifications of the technical person primarily responsible for overseeing the preparation of the reserves estimates as required by Item 1202(a)(7) of Regulation S-K. |
RESPONSE:
In future filings, we propose to identify a single person primarily responsible for overseeing the preparation of the reserves estimates. Background information on David M. Hall, the Chief Executive Officer of CIE, and David Voyticky, our then Acting Chief Financial Officer, is included in Part III of the Form 10-K. The Company proposes to provide more detailed technical qualifications of the single person responsible for overseeing the preparation of reserves estimates in future filings. Assuming that person will be Mr. Hall for the current fiscal year, such disclosure would read substantially as follows:
“Mr. David M. Hall, the Chief Executive Officer of CIE, is the technical person primarily responsible for the overseeing of the preparation of our proved reserves estimates by our independent petroleum engineers. Mr. Hall has over 20 years of experience in oil and gas operations, development and reservoir engineering, including over 20 years of experience with many of the Company’s Alaska oil and gas assets, as a result of his former positions with our predecessors in title, Forest Oil and Pacific Energy. Mr. Hall experience includes: (i) managing our geological, geophysical, production, and drilling groups, including setting directives for these groups; (ii) estimating reserves and forecasting for property evaluations and development planning; (iii) predicting reserves and performance for well proposals; (iv) supervising and working with third party reserve engineering firms; (v) developing and applying reservoir optimization techniques; (vi) overseeing the development of reservoir monitoring and surveillance programs, and overseeing performance of reservoir characterization studies; and (vii) coordinating geological and petrophysical studies.”
Risk Factors, page 16
The development of our proved undeveloped reserves may take longer…,page 20
| 9. | You include the uncertainty of unproved reserve estimates in this risk factor even though you have not disclosed unproved reserves. Please remove this risk factor unless you intend to disclose unproved reserve estimates. |
RESPONSE:
The reference to unproved reserves will be removed in future filings unless included as part of disclosure regarding probable or possible reserves in compliance with Commission rules.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 33
| 10. | In the second bullet point on page 34 of your Form 10-K, you disclose that about 2.5 MMCFD in fuel gas demand is now supplied by the RU-3 and RU-4 wells. It appears that these wells have proved gas reserves attributed. Please explain to us whether you have included these fuel volumes in your proved reserves. If so, explain to us your treatment of natural gas pricing and production cost for these volumes in the determination of the standardized measure. Also reconcile this fuel gas use (343 MMCF [= 57,123 BOE x 6 MCFE/BOE]) from page 8 with annual natural gas production figures (133 MMCFG in fiscal 2013) on page F-30. |
RESPONSE:
Except in the limited circumstance described in our response to Comment 4 above related to the disclosures on page 8 of the Form 10-K, the Company has not included volumes of fuel gas in its historic production volumes and has excluded from its estimates of proved reserves the estimated future production volumes to be used as fuel gas. Accordingly, the natural gas production figures in the proved reserves reconciliation table on page F-30 exclude produced fuel gas. No future cash inflows or outflows related to fuel gas production or use has been included future net cash flows from estimated proved reserves used in the calculation of standardized measure.
Notes to Consolidated Financial Statements, page F-7
Supplemental Oil and Gas Disclosures (Unaudited), page F-29
Proved Reserves, page F-30
| 11. | We note your statement, “The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company’s proved developed reserves….” Please modify this to disclose that the calculation of the standardized measure utilizes proved undeveloped as well as proved developed reserves. You may refer to FASB ASC 932-235-50-30. |
RESPONSE:
We acknowledge that the statement on page F-30 errantly refers solely to “proved developed reserves” in referencing the standardized measure and will be corrected in future filings. The standardized measure is correctly calculated utilizing net cash flows from all of the Company’s proved reserves throughout the Form 10-K.
| 12. | You state “…the price per MMcf of natural gas was $6.37 for the Cook Inlet reserves…” for fiscal 2013. The SEC price is the average of the 12 prior first day of the month received prices per MCF and will likely approximate the annual average. Your annual average Cook Inlet natural gas price for fiscal 2013 is $3.99 on page 37. Please explain this significant price increase to us. If this increase is due to gas sales contracts, please furnish them to us. |
RESPONSE:
Our Alaska natural gas sales in fiscal 2013 were sporadic and immaterial, resulting in revenues (net of transportation charge) of less than $41,000. The bulk of such sales consisted of incidental sales to the operator of the Three Mile Creek field in part for use as fuel gas at a negotiated price with the remainder resold by the Three Mile Creek operator. Thus, the $3.99 per Mcf average realized sales price for Alaskan natural gas production was the result of these negotiated terms with the third party operator and a disproportionately large transportation charge in light of the small volumes.
The Company did not believe its occasional sales of small amounts of natural gas in fiscal 2013 constituted a market price for produced Cook Inlet natural gas. While historically a local market has been found for substantially all natural gas produced and accessible by pipeline in the Cook Inlet, spot prices are not continuously quoted and prices and deliveries are based upon local gas sales contracts with end users which are negotiated at prices loosely related to the price of alternative fuels. Natural gas pricing of Alaskan natural gas reserves in the Davis reserve report was determined by Davis based on an average price of five third party gas sales contracts of another Cook Inlet operator in effect during fiscal 2013 with which Davis was familiar, which resulted in an average price of approximately $6.87 per Mcf reduced by a $0.50 per Mcf estimated transportation charge to $6.37 per Mcf reflected in the Davis report. Subsequent to the end of fiscal 2013, the Company has entered into its own natural gas sales contracts at prices ranging from $6.00 to $7.00 per Mcf, including certain price escalators applying in future years.
The Company submits that, because of the relatively small amount of Alaskan natural gas proved reserves as of April 30, 2013, had its natural gas proved reserves been calculated in the Davis report at the artificially lower average price of $3.99 per Mcf, the reduction of Alaskan proved natural gas reserve volumes would have been negligible and the reduction in present value of future net revenues of total Company proved reserves (PV-10) would be less than 2.0%.
The Company acknowledges the typographical error in the reference to “price per MMcf” which the Company will correct in future filings.
Exhibit 99.1
| 13. | Please file an engineering report that identifies the assumptions made by the third party as well as a statement that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report. You may refer to Item 1202(a)(8)(iv) of Regulation S-K. |
RESPONSE:
We understand that a Davis representative will contact Mr. Winfrey concerning this comment to their reserve report letter. Davis respectfully submits that their report filed as Exhibit 99.1 to the Form 10-K complies with Item 1202(a)(8)(iv) of Regulation S-K citing the following excerpted provisions of their report dated July 1, 2014:
“Davis has reviewed 100% of CIE’s proved properties located in Alaska. It is our opinion that these properties represent all of CIE’s oil and gas assets that may be classified as proved as per the Securities Exchange Commission directives as detailed later in this report.
“Reserve Estimates
The reserves presented in this report have been estimated using engineering and geological methods widely accepted in the industry. 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 and proved undeveloped reserves estimates were made using volumetric methods.
The accuracy of reserve estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of that data. The quantities presented herein are estimated reserves of oil that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty. The reserves are calculated using acceptable methods and procedures and are believed to be reasonable; however, future reservoir performance may justify revision of these estimates.
“General
We have used all methods and procedures as is considered necessary under the circumstances to prepare this report.”
* * * * *
Please direct any questions that you have with respect to the foregoing or if any additional supplemental information is required by the Staff, please contact myself at (713) 882-6812 or our securities counsel, Jim Prince of Vinson & Elkins L.L.P., at (713) 758-3710.
| Very truly yours, | |
| MILLER ENERGY RESOURCES, INC. | |
By: /s/ John M. Brawley | |
| Name: John M. Brawley | |
| Title: Chief Financial Officer | |
| Enclosures | |
| cc: | Kurt C. Yost |
| Senior Vice President and General Counsel | |
| James M. Prince | |
| Vinson & Elkins L.L.P. | |