October 10, 2012
Mr. H. Roger Schwall
Assistant Director
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, 2011 | |
| Filed April 16, 2012 | |
| File No. 001-14837 | |
Dear Mr. Schwall:
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 September 25, 2012 (the “Comment Letter”) relating to our annual report on Form 10-K for the fiscal year ended December 31, 2011 (the “2011 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, 2011
Business, page 6
Delivery Commitments and Purchases of Natural Gas, NGLs and Oil, page 15
1. We note you have significant delivery commitments attributable to the Horn River Asset for the period 2012 through 2016 and thereafter. According to the information on page 10 and elsewhere in your filing, there are only a limited number of proved wells in the Horn River Asset already drilled or planned for drilling in the period from 2012 through 2016. Tell us what steps you will take to ensure that available reserves and supplies are sufficient to meet such commitments attributable to the Horn River Asset as required under Item 1207(a)(3) of Regulation S-K.
Response: Our 2012 capital program for our Horn River Asset is disclosed on page 40 in Item 7 of the 2011 Form 10-K and indicates the significance of our 2012 investment in the Horn River Basin. In addition to our existing well portfolio at December 31, 2011, on page 10 we disclosed our expectation for eight new wells to come online in 2012. The initial production results of these wells were included on page 28 in our Form 10‑Q for the quarter ended June 30, 2012 (filed on August 9, 2012) and represented results consistent with our existing producing wells. We acknowledged on pages 7, 8 and 10 of the 2011 Form 10‑K that we are in transition from the exploration phase to full development in this basin and discussed our longer range development program to convert our exploratory licenses to leases. We further disclosed on page 15 of the 2011 Form 10‑K that we will utilize production volumes from our wells plus royalty volumes we control and other third-party volumes toward meeting our commitments. Any shortfall to our minimum delivery commitments from these sources would be funded with cash or purchased third‑party volumes; however, we disclosed that we did not expect this to be a material amount in the near-term.
In future filings we will ensure that when significant increases in production are needed to meet our delivery commitments, our disclosure will include, in close proximity, appropriate discussion of how our future capital program is designed to achieve the necessary production levels for the next one to three years.
1
Management's Discussion and Analysis of Financial Condition and Results of Operations, page 38
2. We note your presentation of Organic reserve growth in the table on page 39. Due to the variable components of calculating a reserve replacement measure, please enhance your discussion in close proximity to this disclosure to address each of the following:
•Identify the status of the proved reserves that have been added (e.g., proved developed vs. proved undeveloped).
•Identify the reasons why proved reserves were added. In this regard, explain to investors the nature of the reserve additions, and whether or not the historical sources of reserve additions are expected to continue, and the extent to which external factors outside of managements' control impact the amount of reserve additions from that source from period to period.
•Explain the nature of and the extent to which uncertainties still exist with respect to newly discovered reserves, including, but not limited to, regulatory approval, changes in oil and gas prices, and the availability of additional development capital and the installation of additional infrastructure.
•Indicate the time horizon of when the reserve additions are expected to be produced to provide investors a better understanding of when these reserve additions could ultimately be converted to cash inflows.
•Disclose how management uses this measure.
•Disclose the limitations of this measure.
Response: We respectfully submit to the Staff:
| • | On page 12 of the 2011 Form 10‑K, we include a three-year history of proved reserves categorized as developed and undeveloped. |
| • | On page 108 of the 2011 Form 10‑K, the Supplemental Oil and Gas Information table and related footnotes present the nature of changes in proved reserves for the three years ended December 31, 2011. |
| • | In our Risk Factors, as disclosed in Item 1A and specifically on pages 22 to 25 of the 2011 Form 10‑K, we discuss how uncertainties and events could have an adverse effect on our operations. |
| • | On page 112 of the 2011 Form 10‑K, we presented a summary of the Standardized Measure of discounted future net cash flows, which incorporated estimates regarding projected rates of production and the timing of development expenditures. |
| • | Organic reserve growth is a metric that we use to evaluate how we deploy our capital and an indicator of how successfully we implement our business strategy of pursuing disciplined organic growth. We have included this organic reserve growth ratio as a metric of how successfully we are managing one of our key value drivers. |
| • | Limitations of this measure include all risk factors discussed around our reserve estimates and the ratio is highly influenced by the prices used within the respective reserve reports as required by the guidelines established by the Commission. Additionally, on page 12 of the 2011 Form 10‑K, we state “The proved reserve data we disclose are estimates and are subject to inherent uncertainties. The determination of our proved reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that depends upon the quality of available data and on engineering and geological interpretation and judgment.” We believe that the disclosures made within the 2011 Form 10‑K are adequate and comport with all applicable form requirements. |
In future filings we will include disclosures with the following proposed language in close proximity to our metric discussion:
The organic reserve growth ratio is a supplemental measure that we use to assess how successfully we are at implementing our business strategy of pursuing disciplined organic growth. We believe that total reserve growth is a key value driver of which organic reserve growth is a component. Reserve estimation has inherent limitations which are detailed in our Risk Factors in Item 1A and include assumptions regarding future production rates, timing and amount of future development expenditures, results of geological, geophysical, production and engineering data and economic factors. Any inaccuracies in these assumptions could materially affect the estimated quantities of proved reserves. Item 8 “Supplemental Oil and Gas Information” contains additional information about our reserves.
2
Financial Statements and Supplementary Data, page 64
Note 16. Fortune Creek, page 95
3. We note you formed Fortune Creek, a midstream partnership, with KKR in December 2011 and your statement that “If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements.” Please clarify for us the specific account for the offsetting entry when you recognized this liability. Please provide an analysis to support your accounting treatment. Refer to FASB ASC 460-10-25-4 and 55-23(c). In addition, please clarify how the accretion expense of $4,741 and $4,830 you reported in the first quarter ended March 31, 2012 and second quarter ended June 30, 2012 were determined.
Response: Based on an analysis of the design of the entity and partners' equity at risk, we have determined the Fortune Creek partnership to be a variable interest entity (VIE) under ASC 810. As we disclosed in footnote 16 to the consolidated financial statements included on page 95 of the 2011 Form 10‑K, we have determined that we direct the most significant activities of Fortune Creek and, therefore, are deemed to be the primary beneficiary of the entity and as a result we have consolidated the entity. The partnership interest issued to KKR in exchange for cash was classified as equity within the Fortune Creek stand-alone financial statements. Upon consolidation, this amount is reclassified from equity to partnership liability. KKR's partnership interest does not provide explicit creditor rights (e.g. the right to force the partnership into bankruptcy). However, the substantive economic terms of the concurrently entered into gathering arrangement are structured to provide a certain level of preferential cash flows to KKR regardless of the throughput of the pipeline. Additionally, the liquidation rights provide a remedy to KKR in the event of default on the gathering agreement. The combination of the terms in the gathering and partnership agreements provide rights similar to those of a creditor, because in the event that our Canadian subsidiary does not perform, the parent does not satisfy its guarantee and the required level of cash flows is not paid by the termination of the gathering agreement, KKR can force the partnership to liquidate and thus be made whole. The ability to obtain a disproportionate share of the assets upon liquidation to achieve the required yield is similar to the rights a creditor might have to collateral and/or a security interest in the assets of a borrower in the event of default. The combination of the rights and obligations under the gathering and partnership agreements results in an instrument that is in substance a liability under ASC 480. Based on these facts, we determined the partnership interest held by KKR should be presented as a liability in our consolidated balance sheet.
We considered the guidance in ASC 460-10-25-4 and ASC 460-10-55-23(c), however, because our guarantee relates to the performance under the gathering agreement, which is a contract between two of our consolidated subsidiaries, we do not believe the recognition provisions in ASC 460 were relevant to the circumstances of this arrangement. Specifically, we considered the guidance in ASC 460-10-25-1(f), which discusses guarantees that are not subject to the recognition provisions in ASC 460. However, pursuant to ASC 480 we recorded a liability as discussed in the preceding paragraph.
At each reporting period, we estimate the timing and amount of anticipated future net cash-flows of the partnership that will be allocable to KKR's capital accounts and necessary to achieve the required level of preferential cash flows as of the reporting date. The difference between the calculated amount and the previous periods' carrying balance is recognized as accretion expense on the liability in our consolidated income statement.
Consolidated Quicksilver (Excluding BBEP Reserves), page 108
4. We note your disclosure of the changes in proved reserves for the three years ended December 31, 2011. In footnote (3) you state that “extensions and discoveries for each period presented represent extensions to reserves attributable to additional drilling activity subsequent to discovery. U.S. extensions and discoveries for 2011 are 100% attributable to our Barnett Shale Asset (of which 11% were proved developed).”
For 2011, please tell us the reason you attributed the changes in the Barnett Shale Asset proved developed to extensions and discoveries and not revisions in light of FASB ASC 932-235-50-5. Also tell us if any of the 2011 changes shown as extensions and discoveries attributable to the Barnet Shale were the result of changes in previously reported estimates of proved reserves resulting from new information obtained from development drilling.
Response: We added net reserves of 172 Bcfe in the United States and 76 Bcfe in Canada through extensions. These extensions were all the result of new proved reserves (58 wells in the US and 29 wells in Canada) attributed to locations that previously had been attributed no proved reserves.
3
All of our reported technical revisions were on wells which had previously recognized reserves and resulted from changes in reserves estimates related to changes in performance when compared to the previous estimate.
Exhibit 99.1
5. The reserve report does not clearly state the purpose for which the report was prepared. Please amend the report to comply with Item 1202(a)(8)(i) of Regulation S-K.
Response: In future filings we will request that our third-party preparer incorporate the following language into their reports:
“This report has been prepared for public disclosure by QRI in filings with the U.S. Securities and Exchange Commission (SEC) in accordance with the disclosure requirements set forth in SEC regulations.”
6. We note from the discussion on page 57 of Form 10-K, of the 341 proved undeveloped locations assigned in the Barnett Shale Asset, 60 of those locations are more than one offset. The discussion goes on to state “the current SEC rule allows the recognition of PUD reserves to be booked beyond one offset location where reliable technology exists that establishes reasonable certainty of economic production at greater distances.”
Please tell us how you determined the locations in the Barnett that are more than one offset met the SEC definitions of undeveloped reserves in Regulation S-X Rule 4-10(a)(31) and how you considered the definition of reliable technology in Regulation S-X Rule 4-10(a)(25) in making that determination. Furthermore, we note the third party report contains no discussion of the use of reliable technology that would be required to support the economic producibility of these locations at greater distances. Please amend the report to include the relevant discussion as part of the requirements under Regulation S-K Item 1202(a)(8)(iv).
Response: On page 12 of the 2011 Form 10-K we explain that “to achieve reasonable certainty of our proved reserve estimates, our reservoir engineering team assumes continued use of technologies with demonstrated success of yielding expected results.” In future filings we will request that our third-party preparer incorporate the following language into their reports:
“Undeveloped locations are located within existing producing areas with established production type curves but are not necessarily direct offsets to existing producing wells. A combination of geologic mapping, optimized drilling and completion techniques and statistical analysis of prior drilled wells has proven to result in reliably predicted well results. The reserves for the undeveloped locations are based on statistical results of the existing producing wells in each type curve area.”
7. We note the reserve report includes the weighted adjusted average prices for gas, oil and NGLs used in the evaluation and the relevant benchmark prices for gas and oil but does not include the relevant benchmark price for NGLs. Please amend the report to include the relevant benchmark price for NGLs as part of the disclosure of the primary economic assumptions required in Item 1202(a)(8)(v) of Regulation S-K.
Response: In future filings we will request that our third-party preparer modify their report to clearly indicate that the West Texas Intermediate Crude spot price was used as the benchmark for oil and NGLs.
Exhibit 99.2
8. We note several references in the report to additional information that are not included in Exhibit 99.2:
•Footnote (2): “The total proved values above may or may not match those values on the total proved summary page that follows this letter due to rounding by the economics program.” The referenced summary page in footnote (2) is not included in Exhibit 99.2.
•“Both gross and net gas reserves presented in this report are after shrinkage.” While there is a reference to gross gas reserves, gross gas reserves are not presented in Exhibit 99.2.
4
•“This report includes: (1) summary economic projections of reserves and cash flow for each reserve category and (2) one-line summaries of basic economic data and reserves for each field area evaluated.” The referenced summary economic projections and one-line summaries are not included in Exhibit 99.2.
Please advise or amend the report to include the referenced information as attachments to Exhibit 99.2.
Response: In future filings we will request that our third-party preparer make the following changes to their report:
| • | Footnote 2 of their report will read “The total proved values above may or may not sum arithmetically due to rounding by the economics program.” |
| • | The statement that “Both gross and net gas reserves presented in this report are after shrinkage” will read “Net gas reserves presented in this report are after shrinkage.” |
| • | The sentence which states “This report includes: (1) summary economic projections of reserves and cash flow for each reserve category and (2) one-line summaries of basic economic data and reserves for each field area evaluated.” will be removed because these items are not provided. |
9. We note the reserve report includes a weighted average price after adjustments over the life of the properties of $76.31 per barrel for NGL in contrast to the average realized NGL prices of $64.64 per barrel shown for Canada on page 42 of Form 10-K.
Please reconcile the difference between the weighted average price for NGL in the report and the average realized NGL price as noted in Form 10-K. Additionally, please clarify the methodology used to calculate the weighted average prices as shown in the report and amend the report to include this clarification.
Response: Our average realized price is dependent on the daily spot price over the entire year. Production volumes, which can vary significantly due to the low volumes of NGLs we produce, will also factor into our average realized price. The NGL pricing used in the reserve report is the average of the first of month West Texas Intermediate (WTI) prices adjusted using the historical relationship of WTI prices compared to our realized NGL prices, in accordance with the SEC rule governing reserve recognition. Thus, the difference between the weighted average price for NGLs in the report and the average realized price for NGLs in Canada as noted in the 2011 Form 10-K is entirely attributable to intra-month changes in NGL prices. Because our total NGL revenue in Canada is $0.1 million in 2011, we do not believe further clarification is necessary.
10. You state a portion of the reserves contained in your report are for “behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates” therefore “these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production.” Based the information on page 10 and elsewhere in Form 10-K for the Horn River Asset, we note 14 wells (4 producing and 10 shut-in at December 31, 2011) are assigned to recover the proved developed reserves of 76.3 Bcfe; whereas, two locations are assigned to recover the proved undeveloped reserves of 23 Bcfe. Accounting for the estimated cumulative production in the Horn River based on the data shown on page 41 of Form 10-K, the per well average recovery of the 14 existing wells appears to be significantly lower than the per well average for the two undeveloped locations. Please reconcile for us the apparent differences in the undeveloped per well estimates in comparison to those of the existing producing and shut-in wells and tell us why you consider the undeveloped estimates to be reasonably certain in accordance with Regulation S-X Rule 4-10(a)(24).
Response: Four of the ten wells identified as drilled and cased in the 2011 Form 10‑K were remotely located from the current development area and had no proved reserves assigned to them. The 76.3 Bcfe assigned to the 10 proved developed (4 proved developed producing and 6 proved developed non‑producing) were assigned in two different formations within the Horn River Basin: 6 in the Muskwa formation and 4 in the Klua formation. The Estimated Ultimate Recovery (“EUR”) of these ten wells, including the historical production to date, was 86.8 Bcfe. Based on the performance of the existing producing wells, reserves assigned to the wells in the Muskwa formation were approximately twice the reserves assigned to the wells in the Klua formation. The two proved undeveloped wells were targeting the Muskwa formation, and their reserves are analogous to the average EUR for the developed wells in the Muskwa formation. Reasonable certainty was established by the two undeveloped locations targeting the Muskwa formation being parallel offsets to an active well producing from the Muskwa formation.
5
* * * *
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/ John C. Regan
John C. Regan
Senior Vice President – Chief Financial Officer
| cc: | Jennifer O’Brien | ||
| Kim Calder | |||
| John Hodgin | |||
| U. S. Securities and Exchange Commission | |||
6