 | John M. Brawley | |
| Chief Financial Officer | ||
| Miller Energy Resources, Inc. | ||
| 9721 Cogdill Road, Suite 302 | ||
| Knoxville, TN 37932 | ||
| Tel: (865)223-6575 | ||
| Fax: (865) 691-8209 | ||
| jbrawley@millerenergyresources.com | ||
May 19, 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
Supplemental response dated April 11, 2014
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 May 5, 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 “Annual Report” or “Form 10-K”) and Supplemental Response dated April 11, 2014.
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 Annual Report unless otherwise specified.
Form 10-K for Fiscal Year Ended April 30, 2013
Business and Properties, page 1
Cook Inlet and Susitna Basins, page 2
| 1. | In part, your response to comment 2 in our letter dated February 21, 2014 states “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 [Electrical Submersible Pumps] because such pump failures or replacements are not routinely expected or predictable and production optimization workovers have not been scheduled in the reserve report.” We note that ESP replacement is a routine occurrence in the industry and remarks attributed to your chief executive officer as part of the |
conference call to discuss your April 30, 2013 operating results indicate that pumps need to be replaced every 18-24 months.
Please present support for the assumption that your ESPs will perform without replacement for the economic lives of the wells.
RESPONSE:
The statement previously made by management, was offered in the context of particular historical experience in the Redoubt field with previous operators, Forest Oil and Pacific Energy. The statement was not intended to be an assertion that ESPs are generally prone to premature failure, but that the design of the wells was impacting the lifespan of the ESPs at that time. In the Redoubt field, Forest Oil was running significantly larger ESPs which were placed above restrictive liquid level control valves (“LLCs”). It is our opinion that not only were the LLCs improperly placed below the ESPs, but they were also the incorrect type of LLCs for the application. The LLCs caused too much restriction in the flow path to the ESP intake, which in turn caused insufficient fluid volume needed to properly cool the ESPs. These factors are believed to have caused premature ESP failures. In addition, the ESPs were oversized, requiring even more flow to adequately cool them. This further contributed to premature ESP failures. We believe that with unrestricted and properly placed LLCs, and with properly sized ESPs, we will extend the life of the ESPs to the life of the wells and that it is not necessary to include ESP replacement costs in our capital plan for our reserve report.
Part of our efforts in reworking the Redoubt wells have been focused on removing the flow path restrictions and improving their overall design. As a result of these efforts, we do not believe we will be adversely impacted by these issues going forward and expect to experience a more typical rate of ESP failure.
We have discussed this issue with Davis, and they indicated that the uncertainties involved in determining the length of time that an ESP will continue to function makes it difficult to schedule routine pump replacements, and for that reason, they prefer not to include replacements in their projections. We also note that we previously engaged Ryder Scott Company (“Ryder Scott”) to prepare a reserve report for the Company as of December 1, 2013, and they also chose not include future ESP replacement costs.
Production, Pricing, and Lease Operating Cost Data, page 8
| 2. | We note your response to comment 5 in our letter dated February 21, 2014. Please revise to disclose, for each of the last three years, historical production, average sales prices, and average unit production costs for each of those fields which comprise at least 15% of your total proved reserves or tell us why this disclosure is not required. These fields appear to be Redoubt Shoal and West McArthur River. Please refer to Item 1204 of Regulation S-K [Federal Register /Vol. 74, No. 9 /Wednesday, January 14, 2009 /Rules and Regulations/page 2195] as well as the related discussion on page 2177. |
RESPONSE:
We acknowledge the Staff’s comment and note that Item 1204 of Regulation S-K only requires historical production for the last three fiscal years for fields which comprise at least 15% of total proved reserves. We note that we have included such information with respect to our Alaska operations taken as a whole, however, we will undertake to include in our future filings three fiscal years of production, average sales prices, and average unit production costs for each of the two fields which comprise at least 15% our total proved reserves. As of April 30, 2013, these fields were Redoubt Shoal and West McArthur River.
For the fiscal years ending April 30, 2013, 2012, and 2011, our production, average sales prices and average production costs for Redoubt Shoal and West McArthur River were as follows:
| For the Years Ended April 30, | ||||||||||||||
| 2013 | 2012 | 2011 | ||||||||||||
| Net production - boe | ||||||||||||||
West McArthur River 1 | 211,473 | 246,970 | 265,670 | |||||||||||
Redoubt Shoal 2 | 100,836 | 95,251 | — | |||||||||||
| Average oil price - per bbl | ||||||||||||||
| West McArthur River | $ | 103.74 | $ | 95.33 | $ | 76.46 | ||||||||
| Redoubt Shoal | $ | 100.03 | $ | 89.98 | $ | — | ||||||||
| Average lease operating expenses - per boe | ||||||||||||||
| West McArthur River | $ | 27.22 | $ | 17.16 | $ | 23.91 | ||||||||
Redoubt Shoal 3 | $ | 142.43 | $ | 55.01 | $ | — | ||||||||
______
| 1 | Net production for West McArthur River for fiscal 2013, 2012 and 2011 includes 11,350, 12,669 and 11,166 boe of fuel gas, respectively, which is considered in the calculation of average production cost but excluded from the calculation of average sales prices. |
| 2 | Net production for Redoubt for fiscal 2013 and 2012 includes 25,301 and 3,796 boe of fuel gas, respectively, which is considered in the calculation of average production cost but excluded from the calculation of average sales prices. |
| 3 | Fiscal 2013 average lease operating expenses per boe for Redoubt Shoal includes $7.5 million in workover expenses. |
Oil and Natural Gas Reserves, page 10
| 3. | In part, your response to comment 7 in our letter dated February 21, 2014 states “…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).” With reasonable detail, please tell us the status, as of April 30, 2014, of these four wells. |
RESPONSE:
As of April 30, 2014, (i) RU-2A and RU-5B (previously designated as Redoubt 05A as of April 30, 2013) are producing for sale and the reserves for these wells are considered proved developed; (ii) WMRU-8 was spudded on November 28, 2013, completed on March 3, 2014, and was brought into production on March 4, 2014, but low flow rates of oil were encountered, and an acid stimulation job is planned and will be executed in the third week of May 2014 in an effort to boost production; and (iii) RU-9 (formerly Redoubt South Stepout 9) was spudded on March 2, 2014, has been drilled to approximately 2,700 feet, the casing was set and cemented in place with a final planned depth of approximately 18,500 feet, and it will be removed from our proved undeveloped listing upon the successful completion of drilling, completion and testing, which is currently underway.
| 4. | We note your statement that logistical and harsh weather environment circumstances are “specific circumstances” for the development of proved undeveloped reserves (“PUDs”) to require more than five years beyond initial booking. As these circumstances appear to be typical for Alaska operators, please tell us the allowances you incorporated in the PUD drilling schedule to accommodate down time due to logistics and harsh weather. |
RESPONSE:
We make every attempt to drill PUDs before they go beyond the initial five-year booking, but as previously noted, the Alaska logistics, harsh weather, and rig availability sometimes cause delays beyond our control. In an attempt to stay within the five-year booking to turn PUDs into proved developed reserves, the Company plans at least one year in advance to conduct drilling efforts.
We note in particular that, in our case, we entered into an agreement on June 12, 2011, to construct and deliver a new rig (Rig 35) to the Osprey Platform in Alaska. Under the terms of that agreement, the rig was expected to be assembled and delivered by the end of November 2011. Although the rig manufacturer was reputable and had worked in Alaska previously, inordinate delays arose when the contractor did not keep to the anticipated schedule. Instead of five months to assemble and deliver the rig, the contractor took 14 months before we believed we were in a position to terminate the contractor and finish the work on the rig on our own. That delay cost us an entire drilling season on the platform, though we were able to get Rig 35 certified and operation by the third week of August in 2012.
There is no reason to believe that such a delay will ever recur, and we do not anticipate we will have any ongoing problems developing PUDs within five years of their initial booking.
Exhibit 99.1
| 5. | Your response to comment 13 in our letter dated February 21, 2014 states, in part, that “We understand that a Davis representative will contact Mr. Winfrey concerning this comment to their reserve report letter.” As no such contact has been made, we reissue our prior comment. |
RESPONSE:
We understand that a representative from Davis contacted Mr. Winfrey and comments to their form of reserve report letter for the Company were discussed. Davis has advised the Company that in the future their form of reserve report letters filed with the Commission will contain such revisions to the extent appropriate and relevant.
| 6. | Please tell us why, based on the information in this reserve report, it appears that there are no PUD fixed cost line items for West McArthur River or the Kustatan facility. |
RESPONSE:
Davis has confirmed to us that their report does not include incremental fixed costs associated directly with PUDs because the entirety of such fixed costs have been included as costs related to proved developed producing reserves that are produced from West McArthur River or the Kustatan facility.
| 7. | For each of the three Redoubt Shoal PUD locations listed in comment three above, the ratios of present value at ten percent discount to undiscounted cash flow - .62 to .68 - are significantly higher than that ratio for the Redoubt Shoal Fixed Operating Costs - .43. This appears to imply that the first production from these PUDs is scheduled earlier than the time at which the projected Redoubt PUD fixed operating costs will be incurred. With reasonable detail, please explain these apparent differences to us and address any material change in reserves and projected cash flows. |
RESPONSE:
Similar to the response on Comment 6, the Davis report does not include incremental fixed costs associated directly with such PUDs because the entirety of such costs have been included as costs related to proved developed producing reserves that are produced from the Redoubt Shoal.
* * * * *
In connection with responding to these comments of the Staff, the Company acknowledges that:
l the Company is responsible for the adequacy and accuracy of the disclosure in the filing;
l 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
l 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.
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 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