January 16, 2015 |
Mr. Ethan Horowitz
Branch Chief
Securities and Exchange Commission
Division of Corporation Finance
100 F. Street NE
Washington, D.C. 20549-4628
Re: | Quicksilver Resources Inc. |
Form 10-K for Fiscal Year Ended December 31, 2013 | |
Filed March 17, 2014 | |
File No. 001-14837 |
Dear Mr. Horowitz:
This memorandum sets forth the responses of Quicksilver Resources Inc. to the comments provided by the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) in its comment letter dated December 19, 2014 (the “Comment Letter”) relating to our annual report on Form 10-K for the fiscal year ended December 31, 2013 (the “2013 Form 10-K”). For your convenience, we have repeated the Staff’s comment in bold type face exactly as provided and set forth our response as appropriate within the comment.
Form 10-K for Fiscal Year Ended December 31, 2013
Business, page 6
Proved Undeveloped Resources, page 13
1.We note that your inventory of proved undeveloped drilling locations included four wells that had been recognized as proved reserves for five years or longer. Please quantify the reserves related to these wells, describe the specific circumstances that justified the continued recordation of these reserves, and outline your progress in drilling these four wells. Refer to Rule 4-10(a)(31) of Regulation S‑X.
Response: The details of the four proved undeveloped drilling locations are as follows:
Well Name | Net Reserves (Bcfe) in December 31, 2013 reserve report | Scheduled 2014 Drilling | Status as of December 31, 2014 | |||
Alliance Hugg Unit 4H | 2.94 | April | Producing | |||
Alliance Hugg Unit 6H | 3.00 | April | Producing | |||
Alliance Commerce C 2H | 2.55 | December | Not recognized as PUD | |||
Alliance Commerce C 4H | 4.01 | December | Not recognized as PUD |
These four wells, which represent 1.2% of our total U.S. reserves (an amount we considered not to be material), continued to be included as proved undeveloped well locations at December 31, 2013 even through they were older than five years as each well location was included on our 2014 drilling schedule. Well locations
Mr. Ethan Horowitz
January 16, 2015
Page 2
that are included on our drilling schedule are 1) assigned to a drilling rig currently under contract or 2) scheduled on a drilling rig that is within our capital budget but is not yet under contract based on various factors such as rig term length or timing of the drilling program. Generally, well locations are placed on the drilling schedule because they are the higher return well locations at the time, they will provide leasehold extensions through operations, or pending state or local regulation could result in the well location not being available in the future.
The Alliance Hugg Unit wells were drilled and completed in the second quarter of 2014 and are currently producing. The Alliance Commerce C wells, which represent 0.6% of our total U.S. reserves, were originally scheduled for drilling in the fourth quarter of 2014. However, other higher return wells, which did not have all necessary land work completed at December 31, 2013 (the land work was subsequently completed in 2014) and thus not included in our 2014 drilling plan, were prioritized ahead of the two Alliance Commerce C wells. As such, the scheduling for the two Alliance Commerce C wells shifted and they will not be included as proved undeveloped locations for the year-end reserve report dated December 31, 2014.
2.We note that budgeted capital expenditures for the fiscal year ended December 31, 2014 totaled $48.4 million to drill, complete, and tie-in wells on proved locations. Please describe the progress you have made through September 30, 2014 with regard to the conversion of proved undeveloped reserves and whether you expect to have developed the well locations identified as part of the timeline shown on page 13 of your Form 10-K.
Response: In our 2013 Form 10-K, we reported that 20 proved undeveloped well locations in our Barnett Shale Asset would be developed in 2014. As of December 31, 2014, the status of these 20 proved undeveloped well locations is as follows:
• | Thirteen of these well locations were drilled during 2014, |
• | One well location, added as a proved undeveloped well location in 2013, had unforeseen drilling delays which deferred drilling to January 2015, and |
• | Six locations, four well locations where lower natural gas liquids pricing in 2014 reduced the return on investment and two well locations being the Alliance Commerce C wells discussed above in question 1, were de-prioritized as higher return well locations were identified. These six well locations will not be included as proved undeveloped locations for the year-end reserve report dated December 31, 2014. |
An additional nine well locations were drilled in the U.S. during 2014 that were not included as proved undeveloped well locations in our 2013 Form 10-K.
In our 2013 Form 10-K, we also reported that 32 proved undeveloped locations in our Horseshoe Canyon Asset would be developed in 2014. As of December 31, 2014, 15 of these well locations were drilled in 2014 and 17 well locations were replaced as higher return projects became available. These 17 well locations will not be included as proved undeveloped well locations for the year-end reserve report dated December 31, 2014. An additional 23 well locations were drilled in Canada during 2014 that were not included as proved undeveloped well locations in our 2013 Form 10-K.
Oil and Gas Acreage, page 16
3.It appears that approximately 53.5% of your undeveloped acreage in the United States is scheduled to expire in the fiscal years ended December 31, 2014 and 2015. Please describe the current status of your operations on expiring acreage and tell us whether you have entered into, or intend to enter into, delay rentals. In addition, please quantify any proved undeveloped reserves associated with undeveloped acreage which are scheduled for drilling after lease expiration.
Response: At December 31, 2013, we did not record any proved undeveloped reserves associated with undeveloped acreage. The two largest concentrations of undeveloped acreage expiring in the years ending
Mr. Ethan Horowitz
January 16, 2015
Page 3
December 31, 2014 and 2015 are in our Niobrara Asset in northwest Colorado (38% of our undeveloped acreage expirations in the years ending December 31, 2014 and 2015 in the U.S.) and in West Texas (50% of our undeveloped acreage expirations in the years ending December 31, 2014 and 2015 in the U.S.).
As disclosed in "Strategic Transactions in the Last Five Years" within Item 1 of our 2013 Form 10-K, in March 2014, we executed an agreement with Southwestern Energy Company to sell all of our Niobrara Asset. The transaction closed in May 2014. Further, all undeveloped acreage in our Niobrara Asset had been previously impaired to the full cost pool at December 31, 2013.
The undeveloped acreage in West Texas includes acreage outside of Pecos County, which, as discussed in "Oil and Natural Gas Operations - West Texas" within Item 1 of our 2013 Form 10-K, is outside of our area of focus for drilling operations and was impaired to the full cost pool prior to December 31, 2013. Undeveloped acres in Pecos County of approximately 60,000 gross (50,000 net) are being developed under two separate agreements as discussed in "Strategic Transactions in the Last Five Years" within Item 1 of our 2013 Form 10-K, which agreements resulted in the reduction of our net acreage position in Pecos County by more than 50% during 2014 as a portion was transferred to our joint venture partners. We have and intend to continue to enter into delay rental payments with our partners within the Pecos County area on acreage we believe to be economic.
Our Other U.S. undeveloped acreage, which represents 8% of our undeveloped acreage expirations in the years ending December 31, 2014 and 2015 in the U.S., is primarily located in areas where we previously had operations, but do not intend to develop. The remaining 4% of our undeveloped acreage expirations in the years ending December 31, 2014 and 2015 in the U.S. is located in our Barnett Shale Asset and is acreage that we intend to let expire as we do not believe this acreage provides economic returns. Both the Other U.S. and Barnett Shale undeveloped acreage has been previously impaired to the full cost pool.
4.In connection with the preceding comment, please revise your disclosure to provide additional information regarding the minimum remaining terms of leases and concessions. As currently presented, your disclosure only provides information on acreage expirations for the three fiscal years following the periods covered by your Form 10-K. Refer to Item 1208(b) of Regulation S-K.
Response: As detailed in the table below, approximately 72% of our net undeveloped acreage in the U.S. expires in the next three years. We believe the remaining approximately 28% of our net undeveloped acreage in the U.S. that has expiration terms longer than three years is not be material. In the case of our Niobrara Asset, we entered into an agreement in March 2014 to sell all of our Niobrara Asset, which transaction closed in May 2014. In the case of Other U.S., there are no proved reserves associated with that acreage and it is primarily located in areas where we previously operated, but do not currently intend to develop. Both our Niobrara Asset and Other U.S. acreage had previously been impaired to the U.S. full cost pool. The remaining 6% of the net U.S. undeveloped acreage that has expiration terms longer than three years is located in our Barnett Shale Asset and West Texas Asset and, together, represents 22,677 net acres, which we believe is not material. We acknowledge the Staff’s comment and advise the Staff that, beginning with our 2014 Form 10-K, we will provide additional detail describing expirations beyond three years where material.
Mr. Ethan Horowitz
January 16, 2015
Page 4
As of December 31, 2013 | ||||||||||||
Total Net Undeveloped Acreage | Expirations Three Years or Less (Percentage of Total Net Undeveloped Acreage) | Expirations Greater than Three Years (Percentage of Total Net Undeveloped Acreage) | ||||||||||
Barnett Shale | 24,228 | 11,704 | 3% | 12,524 | 3% | |||||||
West Texas | 145,407 | 135,254 | 34% | 10,153 | 3% | |||||||
Niobrara | 162,990 | 112,734 | 28% | 50,256 | 12% | |||||||
Other U.S. | 71,178 | 29,034 | 7% | 42,144 | 10% | |||||||
U.S. | 403,803 | 288,726 | 72% | 115,077 | 28% |
In Canada, our Horn River undeveloped acreage is primarily covered by long-dated lease terms with material expirations between 2020 and 2023. We acknowledge the Staff’s comment and advise the Staff that, beginning with our 2014 Form 10-K, we will provide additional disaggregation of the expirations by area concentrations and provide additional detail describing expirations beyond three years where material.
Notes to Consolidated Financial Statements
Note 8. Property, Plant and Equipment, page 82
Unevaluated Natural Gas and Oil Properties Not Subject to Depletion, page 84
5.Disclosure in your Form 10-K states that it will take up to an estimated nine more years of exploration and development activity to evaluate your Horn River Asset which appears to be an increase from the prior year when you disclosed that an estimated seven more years of exploration and development activity would be necessary. You also disclose that you expect to significantly limit capital spending on your Horn River Asset as you pursue a strategic transaction that will defray your need to make a significant capital investment. Please tell us whether you have entered into a transaction that will provide you with the necessary capital and describe your current plans to develop your Horn River Asset.
Response: In 2013, we reassessed the estimated time necessary to evaluate our Horn River Asset to reflect our longest dated lease term expiration. In our Form 10-Q for the quarter ended September 30, 2014 (filed on November 10, 2014), we noted that although we have been in discussions on a potential transaction involving our Horn River Asset and have proposed transaction terms, we have reached no agreement on any material terms, including structure or valuation. Accordingly, we developed a formalized marketing process for this asset, along with any and all of our assets. We may be unsuccessful in consummating a transaction involving our Horn River Asset or any of our other assets being marketed on acceptable terms, or at all. We intend to provide an update on our progress in our 2014 Form 10-K.
Note 15. Fortune Creek, page 97
6.We note that you have committed to minimum gross capital expenditures of $300 million for drilling and completion activities in your Horn River Asset. Please describe the contractual terms regarding the cash penalties you will incur if these minimum capital expenditure commitments are not met and explain the statement in you Form 10-K that the cash penalty will be applied against the gathering agreement requirement.
Response: At December 31, 2013, there was $120 million remaining of the gross capital expenditure requirement, which we must satisfy by the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset. The capital expenditure requirement is based on gross expenditures, and we may not be required to spend the entire $120 million, as any working interest
Mr. Ethan Horowitz
January 16, 2015
Page 5
partner's capital expenditures would be applied against the requirement. As disclosed in our 2013 Form 10-K, any shortfall of the required gross capital expenditure remaining at the applicable end date would be payable in cash at that time by us to the Fortune Creek Partnership. Such payment would reduce by an equal amount our cash payments under the gathering agreement in the final months of its initial term and would also reduce the balance of the partnership liability as presented on the consolidated balance sheet. We will provide an update for this commitment in our 2014 Form 10-K.
Note 18. Condensed Consolidating Financial Information, page 102
7.Your disclosure states that the indentures under both your senior notes and your senior subordinated notes distinguish between restricted subsidiaries and unrestricted subsidiaries, but does not appear to address the distinction between restricted guarantor subsidiaries and restricted non-guarantor subsidiaries. Please address any differences between these types of subsidiaries with reference to the relevant terms of the indenture agreement. In addition, please explain how you determined that it was appropriate to include a column as part of your condensed consolidating financial information that presents the sum of the parent entity, the restricted guarantor subsidiaries, and the restricted non-guarantor subsidiaries. As part of your response, please tell us the specific exception per Rule 3-10 of Regulation S-X you applied to support the presentation of condensed consolidating financial information.
Response: Beginning with our 2014 Form 10-K, we will clarify the basis of distinction between the restricted guarantor subsidiaries and the restricted non-guarantor subsidiaries under the indentures by including the following disclosure:
"Under the terms of the indentures, restricted guarantor subsidiaries, which fully and unconditionally and jointly and severally guarantee our obligations under the senior notes and the senior subordinated notes, do not include restricted subsidiaries that are (i) foreign subsidiaries, or those subsidiaries that are not organized under the laws of the United States of America or any state thereof or the District of Columbia (and any subsidiary of such a subsidiary) and (ii) any subsidiary that is not a wholly-owned subsidiary that (1) is classified as a pass-through entity for U.S. federal, state, local and foreign income tax purposes and (2) has no indebtedness."
We note, however, that as disclosed on page 101 of our 2013 Form 10-K, the restricted non-guarantor subsidiaries, like the restricted guarantor subsidiaries, are limited in their activity by the covenants in the indentures for such matters as incurring additional indebtedness, paying dividends, selling assets, making investments and making restricted payments.
We are relying on the exception included in Rule 3-10(f) which provides that financial statements of each subsidiary guarantor need not be presented if (assuming the itemized ownership and guarantee conditions are satisfied) the parent company’s financial statements include, in a footnote, the required condensed consolidating financial information for applicable periods for (i) the parent company, (ii) the subsidiary guarantors on a combined basis, (iii) any other subsidiaries of the parent on a combined basis, (iv) consolidating adjustments and (v) the total consolidated amounts. We believe that the 9-column format of the condensed consolidating financial information satisfies the itemized requirements and provides certain incremental disclosure useful to investors and contemplated by the indentures. In particular, (A) column 1 (from left to right) of the presentation, sets out the applicable company financial information; (B) column 2 sets out the applicable financial information of the subsidiary guarantors on a combined basis; (C) columns 3 and 6 provide the applicable financial information for our restricted and unrestricted non-guarantor subsidiaries, respectively; (D) column 8 provides the applicable consolidating adjustments; and (E) column 9 provides the total consolidated amounts. Because the indentures distinguish between our restricted and unrestricted subsidiaries, as noted above, we believe that segregating the financial disclosure of the restricted non-guarantor subsidiaries and the unrestricted non-guarantor subsidiaries provides investors with helpful financial information regarding credit that supports the notes as well as the portion of the consolidated enterprise subject to the covenants of the
Mr. Ethan Horowitz
January 16, 2015
Page 6
indentures. Similarly, column 5, which consolidates the financial information of the company, the restricted guarantor subsidiaries and the restricted non-guarantor subsidiaries provides financial information that is incremental to the requirements of Rule 3-10(f) but is consistent with the reporting requirements under the indentures which obligate us to provide a detailed presentation of the financial condition and the results of operations for us and our restricted subsidiaries.
8.We note that your senior notes and senior subordinated notes are guaranteed by certain of your domestic subsidiaries (i.e., the restricted guarantor subsidiaries) and that the guarantees are full and unconditional and joint and several. Please revise to disclose any qualifications to the subsidiary guarantees (i.e., release provisions).
Response: As disclosed on page 101 of the 2013 Form 10-K, the guarantees provided by the subsidiary guarantors in respect of the senior notes and senior subordinated notes are full and unconditional and joint and several. In response to the Staff's comment, beginning with our 2014 Form 10-K, we will include the following disclosure:
"The terms of the indentures include customary release provisions providing that a subsidiary guarantor will be released from its obligations under a subsidiary guarantee automatically:
• | upon the sale, disposition or other transfer (other than by lease) of (i) the capital stock of such subsidiary following which such subsidiary guarantor is no longer a subsidiary of us or (ii) all or substantially all the assets of the applicable subsidiary guarantor, in each case, to a person that is not us or a restricted subsidiary of us, provided that such sale, disposition or other transfer is made in compliance with the applicable provisions of the indentures and all of the obligations of the subsidiary guarantor under any credit facility and related documentation or other agreement relating to other indebtedness of us or our restricted subsidiaries terminates upon the consummation of such transaction; or |
• | if we designate any restricted subsidiary that is a subsidiary guarantor as an unrestricted subsidiary in accordance with the applicable provisions of the indentures. |
In addition, the obligations of each subsidiary guarantor under its subsidiary guarantee are designed to be limited as necessary to prevent that subsidiary guarantee from constituting a fraudulent conveyance under applicable bankruptcy, insolvency, reorganization or similar laws and, therefore, such subsidiary guarantee is specifically limited to an amount that such subsidiary guarantor could guarantee without such subsidiary guarantee constituting a fraudulent conveyance."
Supplemental Oil and Gas Information, page 115
9.Please revise your disclosure of changes in the net quantities of proved reserves to present the total quantity of proved reserves by line item for all products (i.e., natural gas, natural gas liquids, and oil). Refer to FASB ASC 932-235-55-2.
Response: We acknowledge the Staff’s comment and advise the Staff that, beginning with our 2014 Form 10-K, we will include in our disclosure of changes in the net quantities of proved reserves a column for total quantity of proved reserves by line item for all products.
10.It does not appear that you have provided disclosure that adequately explains the significant changes in your proved reserves. For example, your explanation of changes in reserve quantities attributable to extensions and discoveries refers to your Barnett Shale Asset, but does not provide detail regarding the factors that resulted in the change. Please revise to provide an appropriate explanation of all significant changes in reserve quantities as required by FASB ASC 932-235-50-5.
Response: Extensions and discoveries in the U.S. for 2013 result from an extension of our Barnett Shale Asset as we optimized our fracturing design and represent approximately 4% of our total reserves at
Mr. Ethan Horowitz
January 16, 2015
Page 7
December 31, 2013, which we believe is not material. We acknowledge the Staff’s comment and advise the Staff that, beginning with our 2014 Form 10-K, we will seek to identify opportunities to further enhance the disclosure of significant reserve changes.
11.Your disclosure of costs incurred in oil and gas property acquisition, exploration, and development on page 117 shows that you incurred development costs of $66.7 million during the fiscal year ended December 31, 2013. However, we note that costs relating to the drilling and completion activities related to your proved undeveloped reserves (“PUDs”) totaled $2.0 million during this period. Please describe the nature of the development costs incurred in 2013 that were not related to your PUDs.
Response: During 2013, in the U.S. we spent approximately $19 million to develop our Niobrara Asset; approximately $16 million to drill locations in our Barnett Shale Asset, which had near-term lease expirations and were classified as probable or possible reserves at December 31, 2012; and approximately $14 million in capitalized overhead and interest related to drilling activities. In Canada, we primarily made expenditures to prepare drilling sites in our Horn River Asset of approximately $14 million, which did not have any associated proved reserves, and capitalized interest and overhead of approximately $3 million.
12.It appears that there was a trend of increasing lease operating expenses from $.68 per Mcfe during the fiscal year ended December 31, 2011 to $.72 per Mcfe during the fiscal year ended December 31, 2012 and $.76 per Mcfe during the fiscal year ended December 31, 2013. In light of this trend, please tell why future production costs used to calculate the standardized measure of discounted future cash flows appear to have decreased on a per barrel basis from December 31, 2012 to December 31, 2013.
Response: The increase in lease operating expense from the fiscal year ended December 31, 2012 to December 31, 2013 is primarily related to non-cash inventory losses, which is not a component in future production costs. Future production costs included in the standardized measure of discounted future cash flows include: certain components of lease operating expense; gathering, processing and treating fees included in gathering, processing and transportation expense; production tax expense; and ad valorem tax expense. The lease operating expense included in future production costs is determined using a combination of a historical 12‑month analysis and current rates for both fixed and variable charges. Thus, higher or lower rates in recently negotiated contracts cause the lease operating expense included in future production costs to vary on a unit basis from historical lease operating expense. In addition, as mentioned above, other components of lease operating expense, such as non‑cash inventory losses and cost recoveries, are excluded when calculating future production costs.
Furthermore, certain operational enhancements that reduce lease operating expense in a current period can lead to much greater reductions in future production costs as the impact is factored in over the lifetime production of each well. For example, the decrease in U.S. future production costs from December 31, 2012 to December 31, 2013 is primarily due to a reduction in 12-month historical workover expense as we implemented more effective and lower cost well enhancements. While this reduction represents only a $0.01 decline in U.S. lease operating expense on unit basis between 2012 and 2013, because workover expense is a fixed charge, as the reduction is applied to declining wells into the future the effect is amplified on a unit basis, resulting in a $0.05 decline in U.S. future production costs on a unit basis from 2012 to 2013. This effect, together with the impact of other reductions in fixed charges resulting from recently implemented operational enhancements generate reductions in future productions costs that are greater than the corresponding reductions to lease operating expense for the current year.
Mr. Ethan Horowitz
January 16, 2015
Page 8
* * * *
Pursuant to your request, Quicksilver Resources Inc. hereby acknowledges that:
• | it is responsible for the adequacy and accuracy of the disclosure in the above-referenced filing; |
• | staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the above-referenced 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. |
If you have any questions or comments regarding any of the foregoing, please contact me at 817‑665‑5000.
Very truly yours, |
/s/ Vanessa Gomez LaGatta |
Vanessa Gomez LaGatta |
Senior Vice President – Chief Financial Officer and Treasurer |
cc: | Diane Fritz | ||
U. S. Securities and Exchange Commission |