Vanguard Natural Resources, LLC
5487 San Felipe, Suite 3000
Houston, Texas 77057
July 8, 2015
VIA EDGAR
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, DC 20549
Attention: H. Roger Schwall, Assistant Director
Ethan Horowitz, Branch Chief
Wei Lu, Staff Accountant
Parhaum J. Hamidi, Staff Attorney
Norman von Holtzendorff, Senior Counsel
Ronald Winfrey, Petroleum Engineer
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| Re: | Vanguard Natural Resources, LLC
Registration Statement on Form S-4 |
Filed June 3, 2015
File No. 333-204696
Form 10-K for Fiscal Year Ended December 31, 2014
Filed March 2, 2015
File No. 1-33756
Dear Mr. Schwall:
This letter sets forth the responses of Vanguard Natural Resources, LLC, a Delaware limited liability company (the “Company”, “Vanguard”, “We”, “Us” or “Our”), to the comment letter from the staff (the “Staff”) of the Division of Corporation Finance of the Securities and Exchange Commission (the “Commission”), dated June 29, 2015, relating to the Company’s Registration Statement on Form S-4 (File No. 333-204696) (the “Vanguard Form S-4”), which was filed with the Commission on June 3, 2015, and the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014 (the “Vanguard Form 10-K”), which was filed with the Commission on March 2, 2015.
Concurrently with the submission of this letter, we are filing through EDGAR Amendment No. 1 to the Vanguard Form S-4 (“Amendment No. 1”). For your convenience, we will hand deliver three full copies of Amendment No. 1, as well as three copies of Amendment No. 1 that are marked to show all changes made since the initial filing of the Vanguard Form S-4.
In this letter, for your convenience, we have recited the comments from the Staff in italicized, bold type and have followed each comment with the Company’s response thereto.
With respect to comment number 2, we are sending the Staff a supplemental response letter containing materials responsive to the comment.
U.S. Securities and Exchange Commission
July 8, 2015
Page 2
Based on our review of the Staff’s comment letter, and as further described herein, we believe that the Vanguard Form 10-K is materially accurate and, accordingly, that amendment is not necessary. As further detailed below, we have proposed updates to our disclosure to be made in future filings with the Commission.
Registration Statement on Form S-4
General
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| 1. | Please note that the staff’s comments with regard to your Form 10-K for the fiscal year ended December 31, 2014 will need to be resolved before we will be in a position to accelerate the effectiveness of your registration statement. |
Response:
We acknowledge the Staff’s comment and recognize that the Staff’s comments on the Vanguard Form 10-K will need to be resolved before the Staff will be in a position to accelerate the effectiveness of the Vanguard Form S-4.
Proposal 1: The Merger, page 65
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| 2. | Please provide us with copies of the LRE board books. |
Response:
We acknowledge the Staff’s comment and have submitted the responsive materials in a supplemental response letter.
Background of the Merger, page 65
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| 3. | Please revise to define the term “non-upstream MLPs.” |
Response:
We acknowledge the Staff’s comment and have revised the disclosure on page 67 to instead refer to “upstream companies other than public MLPs.”
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| 4. | Please expand your disclosure to describe the factors that prompted LRE’s meeting with TPH on January 6, 2015, and disclose whether LRE initiated the meeting. |
Response:
We acknowledge the Staff’s comment and have revised the disclosure on page 67 to describe the factors that prompted LRE’s meeting with TPH on January 6, 2015 and to disclose whether LRE initiated the meeting.
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| 5. | On page 67, you disclose that LRE expanded its search to include upstream MLPs due to “recently depressed commodity prices, challenging capital markets and the overall business environment for upstream MLPs.” Please enhance this disclosure to explain in greater detail |
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July 8, 2015
Page 3
why these cited factors led LRE to begin considering upstream MLPs in addition to the companies that it was already considering.
Response:
We acknowledge the Staff’s comment and have revised the disclosure on pages 67 and 68 to explain in greater detail why LRE began considering upstream MLPs in addition to the companies that it was already considering.
Recommendation of LRE GP’s Board of Directors and Its Reasons for the Merger, page 74
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| 6. | On page 74, you cite current and projected commodity prices and their adverse effects on LRE as a reason why the LRE GP board approved the merger agreement. To the extent that current and projected commodity prices could have similarly adverse effects on your business, please clarify why the LRE GP board viewed this factor as being favorable in its approval determination. For example, if the LRE GP board viewed your business as having a potentially more favorable balance of commodity exposure as among natural gas, oil and NGLs, please clarify that. |
Response:
We acknowledge the Staff’s comment. We understand that the LRE GP board did not view current and projected commodity prices and their adverse effects as being generally positive or favorable in coming to its determination to approve the merger agreement. Changes in the capital markets, borrowing and liquidity issues and the sustainability of future distributions are addressed elsewhere on page 75. Therefore we have deleted the entire bullet from page 75.
Unaudited Pro Forma Combined Financial Information, page 152
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| 7. | Please revise to present information showing the pro forma impact of your proposed merger with Eagle Rock Energy Partners, L.P. exclusive of the pro forma impact of your proposed merger with LRR Energy, L.P. |
Response:
We acknowledge the Staff’s comment and have revised the unaudited pro forma combined financial information to include pro forma financial statements reflecting the impact of our proposed merger with Eagle Rock Energy Partners, L.P. exclusive of the pro forma impact of our proposed merger with LRR Energy, L.P. Please see pages 176 through 192.
Note 2 – Unaudited Pro Forma Combined Balance Sheet, page 161
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| 8. | Please update your presentation to use the most recent stock price at the time of filing your next amendment for determining the value of units to be issued in the proposed transactions with LRR Energy, LP and Eagle Rock Energy Partners, L.P. |
U.S. Securities and Exchange Commission
July 8, 2015
Page 4
Response:
We acknowledge the Staff’s comment and have revised the unaudited pro forma combined balance sheet using the closing price per Vanguard common unit on July 6, 2015 of $14.71, the closing price of the most recent practicable date prior to the filing of Amendment No. 1. Please read pages 165 and 166. We will further update the unaudited pro forma combined balance sheet using the closing price per Vanguard common unit on the most recent practicable date prior to the filing of any subsequent amendment to the Vanguard Form S-4.
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| 9. | We note that the preliminary purchase price allocations for the planned acquisitions result in pro forma goodwill. Please expand your disclosure to provide a qualitative description of the factors that make up this goodwill. |
Response:
We acknowledge the Staff’s comment and have provided an expanded qualitative description of the factors that make up the goodwill. Please see pages 164 and 185.
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| 10. | Pro forma adjustments (b) and (h) relate to borrowings under your reserve-based credit facility to repay outstanding debt balances for LRR Energy, L.P. and Eagle Rock Energy Partners, L.P. Please revise your disclosure in light of the recent change to your borrowing base or tell us why a revision to your pro forma financial statements is not necessary. |
Response:
We acknowledge the Staff’s comment. On June 3, 2015, Vanguard entered into the Eighth Amendment to its Third Amended and Restated Credit Agreement (the “Amended Agreement”), which decreased the borrowing base from $2.0 billion to $1.6 billion. The Amended Agreement, however, provides for an automatic increase in the borrowing base by $200.0 million upon closing of the LRE merger. No revision to our pro forma financial statements is necessary because the amount of debt we are assuming and extinguishing under LRE’s credit agreement and Eagle Rock’s revolving credit agreement does not exceed the amount of debt we have available to borrow under our current borrowing base.
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| 11. | Pro forma adjustments (f) and (l) relate to cash severance payments to be made to employees of LRR Energy, L.P. and Eagle Rock Energy Partners, L.P. Please tell us whether contractual arrangements related to these payments were entered into as part of each of the acquisition agreements. |
Response:
We acknowledge the Staff’s comment. In connection with our proposed acquisition of LRR Energy, L.P., we did not enter into any contractual arrangements with any employees of LRR Energy, L.P. that relate to severance payments. Pro forma adjustment (f) relates to cash severance payments that are expected to be paid to LRE GP’s Chief Financial Officer, Jaime R. Casas, who will be terminated prior to the closing of our proposed acquisition of LRR Energy, L.P. As disclosed on pages
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July 8, 2015
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131 and 132, we expect that Mr. Casas will receive a severance payment of $750,000 immediately prior to the closing of the proposed acquisition, as well as other cash bonuses in an aggregate amount equal to the sum of $250,000 plus a prorated portion of a $250,0000 annual cash bonus. No other employee or director of LRE GP is entitled to or expected to receive any severance payments in connection with the proposed acquisition.
Likewise, in connection with our proposed acquisition of Eagle Rock Energy Partners, L.P., we did not enter into contractual arrangements with any employees of Eagle Rock Energy Partners, L.P. that relate to severance payments. Eagle Rock Energy G&P, LLC, the general partner of the general partner of Eagle Rock Energy, L.P., has existing Executive Change of Control Agreements with each of its Chief Executive Officer, Senior Vice Presidents, and Vice Presidents. Furthermore, in connection with the execution of the Agreement and Plan of Merger, Eagle Rock Energy G&P, LLC amended (i) its Change of Control Protection and Severance Program (which generally covers all employees other than those who have entered into Executive Change of Control Agreements with Eagle Rock), and (ii) Eagle Rock Energy G&P, LLC entered into amendments to its restrictive covenant agreements with each of Joseph A. Mills and Roger A. Fox to clarify certain definitions in these agreements but leaving unchanged certain provisions for additional severance payments that, to the extent Vanguard chooses to pay them post-closing, would trigger non-compete obligations. These amendments were filed on Eagle Rock Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on May 22, 2015.
Therefore, the pro forma adjustment (l) relates to cash severance payments that may be paid to (i) the officers of Eagle Rock Energy G&P, LLC pursuant to their Executive Change of Control Agreements, and, in the case of Messrs. Mills and Fox, also to enforce the non-compete obligations in their restrictive covenant agreements with Eagle Rock Energy G&P, LLC and (ii) other employees pursuant to the Change of Control Protection and Severance Program. Vanguard has not yet determined whether any of the Eagle Rock Energy G&P, LLC officers or employees, as applicable, subject to these agreements will be terminated in connection with the proposed acquisition (nor whether Vanguard will pay to enforce the non-compete obligations in the restrictive covenant agreements between Eagle Rock Energy G&P, LLC and Messrs. Mills and Fox) and therefore we are unable to determine the exact amount of cash severance payments, if any, that will be paid upon the closing of the proposed acquisition.
Note 3 – Pro Forma Adjustments to Unaudited Combined Statements of Operations, page 165
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| 12. | Please expand your disclosure under pro forma adjustments (h) and (p) to explain how the amount of interest expense was determined, including with regard to the interest rate used. |
Response:
We acknowledge the Staff’s comment and have updated our disclosure under pro forma adjustments (h) and (p) to explain how the amount of interest expense was determined, including with regard to the interest rate used. Please see page 167.
Exhibits
U.S. Securities and Exchange Commission
July 8, 2015
Page 6
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| 13. | Please file or incorporate by reference your merger agreement with Eagle Rock. |
Response:
We acknowledge the Staff’s comment and have incorporated by reference our merger agreement with Eagle Rock. Please see the Exhibit Index on page II-5.
Form 10-K for Fiscal Year Ended December 31, 2014
Oil, Natural Gas and NGLs Data, page 8
Proved Undeveloped Reserves, page 11
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| 14. | We note that your conversion fractions of beginning of the year available proved undeveloped reserves to developed status for each of the last three years is about 9.4%, 2.6% and 3.7% for 2014, 2013 and 2012, respectively. The cumulative conversion fraction is about 16%. This pace of PUD location drilling does not appear to have a reasonable likelihood for completion of your development plan within five years of adoption. Rule 4-10(a)(31)(ii) of Regulation S-X states “Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.” Please explain how your PUD conversion performance to date has complied with Regulation S-X. |
Response:
We acknowledge the Staff’s comment. We believe our development plan is in compliance with the requirements of Rule 4-10(a)(31)(ii) of Regulation S-X such that we develop our proved undeveloped reserves within five years from booking date or those reserves are dropped from proved undeveloped reserves. As disclosed in our 2014 Form 10-K, none of our proved undeveloped reserves at December 31, 2014 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves. The conversion percentage calculation provided above does not include those proved undeveloped reserves which have been dropped due to the requirement that PUDs be developed within five years of booking, PUDs acquired, a revised development plan, and a revised recovery estimate or pricing. As a result of acquisitions completed during 2012, 2013 and 2014, continuous changes in our drilling program including the drilling in the Arkoma Basin and a horizontal drilling plan in the Gulf Coast Basin, the development plan is periodically re-optimized which has resulted in some reserves being dropped due to the fact they will not be drilled within five years from the booking date and other reserves being added due to acquisitions. These dropped proved undeveloped reserves are included in the “Revision” category of the proved undeveloped reconciliation as we account for dropped reserves as a revision to a previous estimate while the reserves added from acquisitions are included in the “Purchases of reserves in place” category. Below is a summary of the last three years of proved undeveloped reserves which have been added and dropped and are included in the “Purchases of reserves in place” and “Revision” categories included in our Form 10-K presentation of the detailed changes to proved undeveloped reserves.
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July 8, 2015
Page 7
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| | PUD Reserves Added from Acquisitions (Bcfe) | PUD Reserves Dropped (Bcfe) |
| 2012 | 185.9 | 14.3 |
| 2013 | 31.3 | 66.1 |
| 2014 | 545.0 | 102.5 |
| Total | 762.2 | 182.9 |
If these reserves were included in the conversion calculation then the corresponding proved undeveloped conversion percentages would be 23.3%, 30.4% and 55.1% for a cumulative conversion fraction of approximately 109% over the last three years. We believe this PUD conversion rate percentage supports our compliance with Rule 4-10 (a)(31) and we plan to develop the proved undeveloped reserves that are included in our current development plan. In response to the Staff’s comment, we respectfully propose that in future filings on Form 10-K, we will provide an additional disclosure for the proved undeveloped reserves which have been removed/dropped and added during the current fiscal year.
Reserve Estimation Process, page 11
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| 15. | Item 1202(a)(6) of Regulation S-K states “If the registrant has not previously disclosed reserves estimates in a filing with the Commission or is disclosing material additions to its reserves estimates, the registrant shall provide a general discussion of the technologies used to establish the appropriate level of certainty for reserves estimates from material properties included in the total reserves disclosed. The particular properties do not need to be identified.” Please expand your presentation here to provide such a discussion of your technologies. |
Response:
We acknowledge the Staff’s comment regarding the material additions to our reserves estimates. These material additions are primarily due to the completion of acquisitions of certain natural gas, oil and NGLs properties. In future filings, we propose to add discussions of technologies used to establish the appropriate level of certainty in formulating material additions to reserve quantities similar to the following:
“We use technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, production data, well test data, geologic maps, electrical logs and radioactivity logs. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.”
Developed and Undeveloped Leasehold Acreage, page 14
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| 16. | Item 1208(b) of Regulation S-K requires that the registrant “Disclose, as of a reasonably current date or as of the end of the fiscal year, the amount of undeveloped acreage, both |
U.S. Securities and Exchange Commission
July 8, 2015
Page 8
leases and concessions, if any, expressed in both gross and net acres by geographic area, together with an indication of acreage concentrations, and, if material, the minimum remaining terms of leases and concessions.” Please amend your document to disclose, if any, material acreage lease expiry. Also, tell us the figures for any PUD volumes you have scheduled for drilling after expiration.
Response:
We acknowledge the Staff’s comment regarding the expiration of our acreage. As noted in our 2014 Form 10-K, substantially all of our leasehold acreage is held by production. The leases in which we hold an interest that are not held by production are not material to us since these leases have no PUDs assigned. As of December 31, 2014, approximately 105,000 net acres are scheduled to expire in future periods and no PUD volumes are scheduled to be drilled after expiration. Of the total expiring acreage approximately 10,000 net acres expire in 2015, 12,000 net acres expire in 2016, 74,000 net acres expire in 2017, 3,000 net acres expire in 2018 and 6,000 net acres expire in 2020. We respectfully request to implement, on a prospective basis, expanded disclosure to include any material acreage lease expiry.
Risk Factors, page 26
We have limited control over the activities on properties we do not operate, page 31
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| 17. | We note your statement that you have limited ability to influence or control the operation or future development of non-operated properties. Please tell us the figures for your year-end 2014 non-operated PUD locations and non-operated PUD reserves. Explain to us the fraction of your non-operated PUD reserves that were converted to developed status for each of the last three years. |
Response:
We acknowledge the Staff’s comment. At year-end 2014, our non-operated PUD reserves represented approximately 380.2 Bcfe with a total of 119 net locations to be developed over the next five years. Of these reserves, 370.9 Bcfe and 102 net locations are located in the Pinedale field within the Green River Basin and are operated by Ultra Petroleum Corp. (“Ultra”) and QEP Resources, Inc. (“QEP”). Both operators are continuously drilling and provide operational updates and updated drilling schedules to us quarterly. Due to the continuous activity and the high level of communication with these two operators, we have reasonable certainty that these locations will be developed within the five years from the date on which the PUDs were booked. As of June 30, 2015 we have converted 34.0 Bcfe and 9.9 net locations of our 2014 non-operated PUDs in the Pinedale field, representing a conversion rate of 8.9%. The remaining 10.0 Bcfe of non-operated PUD reserves at year-end 2014 are attributable to 17 net locations and are located in areas with continuous activity on or directly adjacent to our lease hold. This level of activity projected over time provides reasonable certainty that within five years we will convert the remaining non-operated PUD reserves. Our non-op conversion fractions of beginning of the year available proved undeveloped reserves to developed status for each of the last three years are about 8.9%, 11.7% and 7.3% for 2014, 2013 and 2012, respectively.
Management Discussions and Analysis and Results of Operations, page 56
U.S. Securities and Exchange Commission
July 8, 2015
Page 9
Recent Developments and Outlook, page 56
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| 18. | Disclosure on page 29 of your Form 10-K states that continued low prices for oil, natural gas, and NGLs could reduce the amount of oil, natural gas, and NGLs that you can produce economically. Please revise to provide additional language addressing the risks resulting from the low commodity price environment described in your filing along with quantitative disclosure regarding the impact to your reserve quantities. Your revised disclosure should reflect potential scenarios deemed reasonably likely to occur by management. Refer to Item 303(a) of Regulation S-K. For additional guidance, refer to section III.B.3. of SEC Release No. 33-8350. |
Response:
We acknowledge the Staff’s comment. In future filings, should the pricing environment be similar to the current environment, we will provide further explanation in our Recent Development and Outlook section in regards to the risks associated with the low commodity price environment, along with a quantitative disclosure regarding the impact to our reserve quantities similar to the following (changes are reflected in bold type):
“The dramatic decline in commodity prices has had an impact on our unit price. During 2014, our common unit price fluctuated from a closing high of $32.95 on July 25, 2014 to a closing low of $13.59 on December 15, 2014. This low commodity price environment has had and will continue to have a direct impact on our revenue, cash flow from operations and Adjusted EBITDA until commodity prices improve. Sustained low prices of oil and natural gas could have a material adverse impact on our financial condition, profitability, future growth, borrowing base and the carrying value of our oil and natural gas properties. Additionally, continued low prices for oil, natural gas, and NGLs could reduce the amount of oil, natural gas, and NGLs that we can produce economically. For example, if natural gas prices declined by $1.00 per MMBtu and oil prices declined by $6.00 per barrel and production costs remained constant (which has historically not been the case in periods of declining production), our total proved reserves as of December 31, 2014 would decrease from 2.03 MCFE to 1.90 MCFE, based on price sensitivity generated from an internal evaluation. We intend to improve our financial outlook through opportunistic hedging and profitable drilling and acquiring new oil and natural gas properties. We foresee significant long term benefits in acquiring assets in this low price commodity environment.”
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| 19. | You state that you intend to concentrate your drilling on low risk, development opportunities with the majority of drilling capital focused on high BTU natural gas wells during 2015. Please tell us how your drilling plans may impact your reported reserve volumes. Specifically, please tell us about any proved undeveloped reserves that were deferred as a result of your drilling plans for 2015. |
Response:
We acknowledge the Staff’s comment. As stated in our 2014 Form 10-K, we intend to concentrate our drilling on low risk, development opportunities with the majority of drilling capital focused on high BTU natural gas wells during 2015. These locations are concentrated in the Green River Basin and the Gulf Coast Basin and are attributed to our acquisitions completed during 2014. We expect that the results from our 2015 drilling program will increase the number of proved undeveloped locations
U.S. Securities and Exchange Commission
July 8, 2015
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in these areas and subsequently increase proved undeveloped reserves even without any improvement in commodity pricing or reduction in service costs. As a result of our 2015 drilling plan, approximately 41.5 Bcfe of proved undeveloped reserves associated with our operated horizontal Woodford Shale drilling program were deferred by up to two years. While these proved undeveloped locations and reserves are economic in the current commodity price environment, it is our expectation that delaying this development will allow for better economic returns for our unitholders as the price environment improves or development costs are reduced.
Critical Accounting Policies and Estimates, page 64
Goodwill and Other Intangible Assets, page 66
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| 20. | We note that goodwill was not considered impaired as of December 31, 2014 because the fair value of your reporting unit exceeded its carrying value by 8%. We also note your statement that any further significant decline in the prices of oil and natural gas or significant negative reserve adjustments could change your estimate of the fair value of the reporting unit and could result in an impairment charge. Please expand your disclosure regarding goodwill impairment testing to: |
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| • | describe the methods and key assumptions used and how the key assumptions were determined; |
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| • | discuss the degree of uncertainty associated with these key assumptions; and |
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| • | address potential events and/or changes in circumstances that could reasonably be expected to negatively affect your key assumptions. |
Response:
We acknowledge the Staff’s comment. In future filings we will provide the following further explanation regarding goodwill impairment testing to include discussion of the methods and key assumptions used and how the key assumptions were determined, the degree of uncertainty associated with the key assumptions and potential events and/or changes in circumstances that could reasonably be expected to negatively affect the key assumptions (changes are reflected in bold type):
“We account for goodwill and other intangible assets under the provisions of the Accounting Standards Codification (ASC) Topic 350, “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist using a two-step process.
The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. The first step involves a comparison of the estimated fair value of a reporting unit to its net book value, which is its carrying amount, including goodwill. In performing the first step, we determine the fair value of the reporting unit using the market approach based on our quoted common unit price. Quoted prices in active markets are the best evidence of fair value. However, because value results from the ability to take advantage of synergies and other benefits that exist from a collection of assets and liabilities that operate together in a controlled entity, the market capitalization of a reporting unit with publicly traded equity securities may not be representative of the fair value of the reporting unit as a whole. Accordingly, we add a control premium to the market price to determine the total fair value
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of our reporting unit, derived from marketplace data of actual control premiums in the oil and natural gas extraction industry. The sum of our market capitalization and control premium, is the fair value of our reporting unit. This amount is then compared to the carrying value of our reporting unit. If the estimated fair value of the reporting unit exceeds its net book value, goodwill of the reporting unit is not impaired and the second step of the impairment test is not necessary.
If the net book value of the reporting unit exceeds its fair value, the second step of the goodwill impairment test will be performed to measure the amount of impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.
Determining fair value requires the exercise of significant judgment, including judgments about market prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities, or a group of assets and liabilities, such as a business. As described above, the key inputs used in estimating the fair value of our reporting unit are our common unit price, number of common units outstanding and a control premium. There is no uncertainty associated with our common unit price and number of common units outstanding. The control premium is based on market data of actual control premiums in our industry. Changes in the common unit price, which could result from further significant declines in the prices of oil and natural gas or significant negative reserve adjustments, or changes in market data as it relates to control premiums in the oil and gas extraction industry could change our estimate of the fair value of the reporting unit and could result in a non-cash impairment charge.
We performed our annual impairment tests during 2014, 2013 and 2012 and our analyses concluded that there was no impairment of goodwill as of these dates. However, due to the current decline in the prices of oil and natural gas as well as deteriorating market conditions, we performed an interim impairment test at December 31, 2014. Based on our estimates, the fair value of our reporting unit exceeded its carrying value by 8% at December 31, 2014 and therefore the second step of the impairment test was not necessary. We believe this difference between the fair value and the net book value is appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium is taken into account and in light of the recent volatility in the equity markets.
While no goodwill impairment was recognized at December 31, 2014, any further significant decline in the prices of oil and natural gas or significant negative reserve adjustments could change our estimate of the fair value of the reporting unit and could result in an impairment charge.”
Capital Resources and Liquidity, page 68
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| 21. | We note that you expect to fund your drilling capital expenditures and distributions to unitholders with cash flow from operations. Please revise to provide additional detail |
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July 8, 2015
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supporting this statement as it appears that cash used for capital expenditures and distributions during the fiscal year ended December 31, 2014 exceeded cash flows from operating activities. Refer to Item 303(a)(1) of Regulation S-K.
Response:
We acknowledge the Staff’s comment. Capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $142.0 million during the fiscal year ended December 31, 2014. Estimated maintenance capital expenditures totaled $116.5 million while the balance of $25.5 million was attributable to growth capital expenditures. In our fourth quarter earnings press release we disclose Distributable Cash Flow Available to Common and Class B Unitholders. Distributable Cash Flow Available to Common and Class B Unitholders is a non-GAAP financial measure used by our management as a tool to measure the cash distributions we could pay our unitholders. For the fiscal year ended December 31, 2014 we had an excess of distributable cash flow after maintenance capital expenditures and distributions to unitholders of $7.8 million. In future filings we will revise the statement in our Form 10-K Capital Resources and Liquidity section to state the following (changes are reflected in bold type):
“We expect to fund our maintenance capital expenditures and distributions to unitholders with cash flow from operations.”
*****
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July 8, 2015
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The Company acknowledges that:
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| • | should the Commission or the staff, acting pursuant to delegated authority, declare the filing effective, it does not foreclose the Commission from taking any action with respect to the filing; |
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| • | the action of the Commission or the staff, acting pursuant to delegated authority, in declaring the filing effective, does not relieve the company from its full responsibility for the adequacy and accuracy of the disclosure in the filing; and |
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| • | the Company may not assert staff comments and the declaration of effectiveness 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 or comments you have regarding our responses, the Vanguard Form S-4 or the Vanguard Form 10-K to undersigned by phone at (832) 327-2259 or Douglas V. Getten of Paul Hastings LLP at (713) 860-7340.
Thank you for your assistance.
Very truly yours,
|
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| By: | /s/ Scott W. Smith |
| | Scott W. Smith |
| | President and Chief Executive Officer |
| | Vanguard Natural Resources, LLC |
cc: Scott W. Smith, President, Chief Executive Officer and Director, Vanguard Natural Resources, LLC
Douglas V. Getten, Partner, Paul Hastings LLP
