Vanguard Natural Resources, LLC
5487 San Felipe, Suite 3000
Houston, Texas 77057
July 8, 2016
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, Accounting Branch Chief
Sandra Eisen, Staff Accountant
Lisa Krestynick, Staff Attorney
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| Re: | Vanguard Natural Resources, LLC
Form 10-K for Fiscal Year Ended December 31, 2015 |
Filed March 8, 2016
File No. 1-33756
Vanguard Natural Resources, LLC
Form 8-K filed May 2, 2016
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 27, 2016, relating to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (the “Form 10-K”), which was filed with the Commission on March 8, 2016 and to the Company’s Current Report on Form 8-K (the “Form 8-K”), which was filed with the Commission on May 2, 2016.
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.
Based on our review of the Staff’s comment letter, and as further described herein, we believe that the Form 10-K and the Form 8-K are 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.
With respect to comments 1 and 6 hereof, we are supplementally providing additional information in
a separate confidential letter (the “Supplemental Letter”) to the Staff pursuant to Rule 83 of the
Commission’s Rules on Information and Requests, 17 C.F.R. § 200.83.
Form 10-K for Fiscal Year Ended December 31, 2015
Business, page 1
Oil, Natural Gas and NGLs Data, page 9
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Page 2
Proved Undeveloped Reserves, page 12
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| 1. | We note your response to prior comment 2 regarding forecasted cash flows that will be used to finance your drilling development plan. It does not appear that each of the items listed as part of your disclosure of contractual obligations along with the cash required for other items such as premium payments on derivative contracts and preferred dividends in arrears are reflected in your analysis. Please revise your analysis or tell us why these types of capital requirements do not need to be considered. |
Response:
We acknowledge the Staff’s comment. As disclosed in our Form 10-K, our operating cash flows are the primary funding source of our capital drilling plan. We direct the Staff to Exhibit A of the Supplemental Letter for an updated presentation of our forecasted cash flow projection reflecting our asset retirement obligations and our lease financing obligations presented in our contractual obligations table in our Form 10-K.
As illustrated in Exhibit A of the Supplemental Letter, all necessary and required cash outflows and inflows have been included in the forecasted cash flow and below is a summary explaining the inclusion or exclusion of any of our contractual obligations, along with the cash required for other items such as premium payments on derivative contracts and preferred dividends in arrears.
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| • | Asset Retirement Obligations have been added to our forecasted cash flow projection as a separate line item representing the estimated cash outflow associated with future plugging and abandonment costs of oil and natural gas wells over the next five years per our contractual obligations table in our Form 10-K. |
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| • | Derivative Liabilities for commodity and interest rate derivative contracts represent the fair market value of our gross (prior to netting) liabilities associated with our commodity and interest rate hedge contracts. The cash outflows associated with our commodity contracts were included in the Hedging Revenue line item of our forecasted cash flow presented in Exhibit A of the Supplemental Letter, while the cash outflows associated with our interest rate contracts were included in the Interest Expense line item of our forecasted cash flow presented in Exhibit A of the Supplemental Letter. |
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| • | Reserve-Based Credit Facility (as defined in our Form 10-K) of $1.7 billion was excluded from our forecasted cash flow as it is the expectation of management that this debt will be refinanced and terms of this debt will be extended in the normal course of our business. |
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| • | Similarly, our outstanding 8.375% Senior Notes due 2019 and 7.875% Senior Notes due 2020 were excluded from our forecasted cash flow as it is the expectation of management that this debt will be refinanced and terms of this debt will be extended in the normal course of business. However, the interest due on the outstanding 8.375% Senior Notes due 2019 and 7.875% Senior Notes due 2020 over the next |
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five years is included in the Interest Expense line item of our forecasted cash flow presented in Exhibit A of the Supplemental Letter.
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| • | Operating lease obligations over the next five years were included in the Cash G&A line item of our forecasted cash flow presented in Exhibit A of the Supplemental Letter. |
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| • | Development commitments of $38.0 million as of December 31, 2015 are included in our five-year drilling development plan. |
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| • | Firm transportation and processing agreement obligations were included as part of the O&G Operating Cash Flow-PDP line item of our forecasted cash flow presented in Exhibit A of the Supplemental Letter. These obligations are included in and are an integral part of the forecasting of price differentials from the New York Mercantile Exchange (“NYMEX”) forward strip price in the form of firm transportation fees and processing fees per MCF. |
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| • | Lease Financing Obligations have been added as a separate line item to our forecasted cash flow presented in Exhibit A of the Supplemental Letter. Lease Financing Obligations represent the estimated cash outflow associated with the minimum future lease payments, including interest, per our contractual obligations table in our Form 10-K. |
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| • | Premium Payments associated with our hedge contracts were included in the Hedging Revenue line item of our forecasted cash flow presented in Exhibit A of the Supplemental Letter, netted with the net cash inflows from our hedging contracts. |
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| • | Preferred distributions in arrears are excluded from our forecasted cash flows as these distributions are not required to be made pursuant to the Company’s Fifth Amended and Restated Limited Liability Company Agreement, dated September 15, 2014 (the “LLC Agreement”) and thus are optional cash outflows and are only paid at management’s discretion depending on the commodity environment and availability of distributable cash flow. |
Furthermore, as illustrated in Exhibit A of the Supplemental Letter, we continue to expect our cash flows from operations will enable us to finance our drilling development plan while also reducing borrowing under our Reserve-Based Credit Facility.
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| 2. | We note that you are assuming that commodity price levels trend in a manner consistent with the New York Mercantile Exchange (“NYMEX”) forward strip price. Explain how you considered other possible scenarios such as prices staying at current levels. With your response, tell us how your analysis considered adjustments (i.e., price differentials) relating to location, quality, and product such as physical pricing points not based on the Cushing, Henry Hub or Mont Belvieu market prices, along with any transportation, gathering, and processing costs. |
Response:
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July 8, 2016
Page 4
We acknowledge the Staff’s comment. To clarify, the NYMEX forward strip price used in our cash flow projections is a starting point price that is adjusted for historical and forecasted basis differential and gathering, processing and transportation fees, in order to arrive to a net realized price to be used in our forecasted cash flows. The adjustments for historical differentials were computed on a contract-by-contract basis by comparing historical benchmark prices to the historical prices actually received by us. The mix of the historical differentials varies by property based on each property’s production and marketing situation. Transportation fees and other price differentials vary based on the distance of the property from the delivery point and other price factors that vary from contract to contract.
Due to the volatile nature of the energy markets, it is difficult to estimate future prices of oil, natural gas and NGLs. Based on historical price trends, the NYMEX forward strip price represents the best estimate of future price levels (showing both decreases and increases from current levels based on external factors disclosed in Item 1A. Risk Factors in our Form 10-K) and as such is considered the baseline in our forecasting assumptions. These pricing assumptions will then determine our investment decisions and the related net cash flows associated with these investments. For example, if we assumed a flat price scenario, although rare, this would lead to a decrease in our capital spending and a decrease in O&G operating cash flows that would then be partially offset by an increase in our hedging revenues (hedge price would be higher than market price).
In addition, as disclosed in our correspondence letter dated August 20, 2015 and on page 13 in Item 1 of our Form 10-K, although a final investment decision to drill the PUDs location has been made by the time the PUD is booked, the timing of such drilling is subject to change based on a number of factors, with pricing levels being the number one factor. We attempt to maximize the rate of return on capital deployed, which requires that we continually review and re-assess all investment options available.
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| 3. | Your response to prior comment 2 states that you would seek additional funding from public and private debt, equity capital resources, joint ventures, and asset sales if cash flow from operations becomes insufficient to continue financing the development of your proved undeveloped reserves. Tell us more about how restrictions and covenants associated with currently outstanding debt which limit your ability to incur additional indebtedness or issue preferred units will affect your ability to obtain additional sources of funding. |
Response:
We acknowledge the Staff’s comment.
The provisions governing the Company’s ability to incur additional debt can be found in Section 4.09 of the Company’s indenture, dated as of February 10, 2016, governing its outstanding 7.0% Senior Secured Second Lien Notes due 2023 (as supplemented from time to time, the “Second Lien Indenture”), Section 5.09 of the Company’s indenture, dated as of April 4, 2012, governing its outstanding 7.875% Senior Notes due 2020 (as supplemented from time to time, the “Senior Indenture;” together with the Second Lien Indenture, the “Indentures,” and each individually an “Indenture”), Section 4.04 of the Intercreditor Agreement, by and among Citibank, N.A., as priority lien agent, and U.S. Bank National Association, as second lien collateral trustee, and
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acknowledged and agreed to by Vanguard Natural Gas, LLC, VNR Finance Corp. and the Company (the “Intercreditor Agreement”) and the Third Amended and Restated Credit Agreement, dated as of May 26, 2016 (as amended from time to time, the “Credit Agreement”), among Vanguard Natural Gas, LLC, a Kentucky limited liability company and a wholly owned subsidiary of the Company, as borrower, Citibank N.A., as administrative agent and issuing bank, and the financial institutions party thereto. Our Indentures, Intercreditor Agreement and Credit Agreement do impose some limitations on our ability to incur additional indebtedness.
However, we do have the capacity to access the capital markets and to issue additional debt. The Company may continue to issue first lien debt and unsecured debt, as it is in compliance with the fixed charge coverage ratio required by the Indentures. Furthermore, under the Credit Agreement, the Company may issue approximately $225 million in additional second lien debt. The borrowing base deficiency at this time is approximately $103.5 million. Under the Company’s Credit Agreement, the Company will make six equal monthly installments of approximately $17.3 million which began on June 27, 2016. The Company expects that its excess cash flow forecasted for the remainder of the year will allow the Company to satisfy this requirement and be back in compliance under the Credit Agreement.
The Company is also currently able to obtain additional sources of funding through the equity capital markets. The provisions in the LLC Agreement place no prohibition on the issuance of equity securities while distributions are in arrears.
Sections 14.5(c)(ii), 15.5(c)(ii) and 16.5(c)(ii) of the LLC Agreement provide for the voting rights of holders of our outstanding Series A preferred units, Series B preferred units and Series C preferred units (collectively, the “Preferred Units”) regarding any issuance of securities that are not expressly subordinated to, or senior to, the Preferred Units. First, if at any time the Company chooses to issue securities that are senior to the Preferred Units, the Company must receive the affirmative vote or consent of at least 66-2/3% of Preferred Units, voting together as a class. Also, when cumulative distributions payable on any class of the Preferred Units are in arrears, then the Company must receive the affirmative vote or consent of at least 66-2/3% of Preferred Units, voting together as a class, to issue any securities that are not expressly subordinated or senior to the Preferred Units. Assuming the Company receives such votes or pays distributions in arrears through that date, the Company may continue to issue Preferred Units or to create and issue new classes of securities.
Even if the Company is not able to do so, the LLC Agreement will not prohibit the issuance of an unlimited number of common units or preferred units that are subordinated to the Preferred Units. Thus, the Company is in a position to seek additional funding from equity capital resources in addition to funding through additional indebtedness.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 65
Results of Operations, page 68
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| 4. | In response to prior comment 6, you state your intention to identify the types of derivative contracts included in the calculations underlying the summary disclosure regarding your hedging program in future filings. As part of your revised disclosure, also explain how the |
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derivative contracts excluded from these calculations could cause the summary information to differ from your actual operating results.
Response:
We acknowledge the Staff’s comment. To address this comment, in future annual reports on Form 10-K we will provide additional disclosure identifying the types of derivative contracts included in the calculation underlying the summary disclosure regarding our hedging program and how the exclusion of certain derivative contracts from these calculations could cause the summary information to differ from our actual operating results similar to the following (certain text from the Form 10-K has been rearranged and, with the exception of the heading, changes are reflected in bold type):
Form 10-K Page 92
The calculations underlying the summary disclosure above are based on fixed price swaps, three-way collars, puts and range bonus accumulators and these calculations exclude basis swap contracts, calls sold and swaptions. The weighted average price for oil and natural gas will fluctuate based on the value of the existing three-way collars and short puts as the respective prices settle. The above weighted average prices are calculated based on forward strip commodity prices as of February 29, 2016. The summary information above for 2016 may differ from actual operating results due to the following factors (i) changes in our actual hedge volumes and weighted average prices due to new hedge contracts or terminations of existing contracts, (ii) production volumes that are not hedged, (iii) changes to our realized price due to differentials and other revenue deductions, and (iv) the exclusion of basis swap contracts, calls sold and swaptions from the above calculations.
Notes to Consolidated Financial Statements
Supplemental Oil and Natural Gas Information, page 134
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| 5. | As noted in prior comment 7, oil and gas producers are required to include the cash outflows associated with the settlement of an asset retirement obligation in calculating the standardized measure of discounted future cash flows. Please revise your disclosure accordingly. |
Response:
We acknowledge the Staff’s comment.
In future annual reports on Form 10-K we will include the cash outflows associated with the settlement of an asset retirement obligation in calculating the standardized measure of discounted future cash flows.
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| 6. | Your response to prior comment 8 does not appear to address the significance of abandonment costs to the future development costs line item in your calculation of the |
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standardized measure of discounted future cash flows. Please expand your materiality analysis to address the impact of abandonment costs to this line item.
Response:
We acknowledge the Staff’s comment.
We direct the Staff to Exhibit B of the Supplemental Letter for a schedule disclosing the materiality analysis of abandonment costs to the future development costs line item in the calculation of the standardized measure of discounted future cash flows. The abandonment costs, net of salvage value, at each of the three years ended December 31, 2013, 2014 and 2015 was $172.4 million, $284.5 million and $389.9 million, respectively. These costs represented 48%, 34% and 59% of our undiscounted future development costs for each of the three years ended December 31, 2013, 2014 and 2015. However, because the development costs are expended in the early years of the lives of the wells and the abandonment costs are expended in the later years of the lives of the wells (refer to Section 1.3 of Exhibit B of the Supplemental Letter for the schedule of abandonment costs by year), it is important to compare these two on a discounted measure. The present value of our abandonment costs, net of salvage value, at each of the three years ended December 31, 2013, 2014 and 2015 was $17.2 million, $25.0 million and $39.2 million, respectively. These costs represented 6%, 4% and 7% of our discounted future development costs for each of the three years ended December 31, 2013, 2014 and 2015. We determined that the present value of our abandonment costs amounted to less than 7% of the discounted future development costs for each of the years presented in our Form 10-K, and believe such a limited impact to be immaterial for disclosure purposes.
As stated in our response to comment 5 above, in future annual reports on Form 10-K we will include the cash outflows associated with the settlement of an asset retirement obligation in calculating the standardized measure of discounted future cash flows.
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| 7. | We note that the schedule of abandonment costs provided in response to prior comment 8 reflects the net costs to plug and abandon your wells. Tell us whether this schedule also includes incremental costs related to equipment, facilities, gathering lines, and other remediation obligations associated with leasehold acreage. |
Response:
We acknowledge the Staff’s comment. To clarify, the schedule of abandonment costs provided in response to prior comment 8 of the correspondence letter dated May 27, 2016, reflects the net costs to plug and abandon the oil and natural gas well and facilities (including the Elk Basin, Big Escambia Creek and Fairway Gas plants). The costs include the cost of the removal of all tangible equipment and the cost to restore the leasehold acreage to its original state in accordance with state regulation.
Form 8-K filed May 2, 2016
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| 8. | With respect to your disclosure of highlights for the period, we note the following: |
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| • | You present non-GAAP measures without also presenting the most directly comparable GAAP measure; and |
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| • | The non-GAAP measures precede the GAAP-basis measure presented. |
In addition, a quantitative reconciliation of forward-looking non-GAAP information is not included in your Form 8-K filed on March 4, 2016. These presentations appear to be inconsistent with the updated Compliance and Disclosure Interpretations issued on May 17, 2016. Please review this guidance when preparing your next earnings release.
Response:
We acknowledge the Staff’s comment. In our future earnings releases we will present any non-GAAP information in accordance with the updated Compliance and Disclosure Interpretations issued by the Commission on May 17, 2016.
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| 9. | We note that you present the non-GAAP measure “Adjusted Net Income Attributable to Common and Class B Unitholders” in your filing on Form 8-K. The reconciliation of this measure presented on your website includes a reconciling item captioned “Change in fair value of commodity derivative contracts” which appears to include adjustments for premiums paid on derivatives that settled during the period, the fair value of acquired derivatives that settled during the period, and the fair value of restructured derivative contracts. It also appears that the adjustment for “Change in fair value of interest rate derivative contracts” reflects cash settlements paid on interest rate derivatives. Explain why these are appropriate adjustments in the calculation of this non-GAAP measure and how these adjustments are consistent with the stated purpose of highlighting the significant fluctuations that commodity price volatility has on your results, particularly as it relates to changes in the fair value of your derivative contracts. With your response, also tell us why a reconciliation of this non-GAAP measure is not presented as part of your filing on Form 8-K. |
Response:
We acknowledge the Staff’s comment. First, we note that “Change in fair value of commodity derivative contracts” does not include adjustments for premiums paid on derivatives during the period presented, the fair value of acquired derivatives that settled during the period presented or the fair value of restructured derivatives contracts. The number reflects the increase or decrease in the mark-to-mark value of the commodity derivatives contract. Any increase in value is reduced from Net Loss Attributable to Common and Class B Unitholders while any decrease is added back into Net Loss Attributable to Common and Class B Unitholders. Making such adjustment allows investors to make a true comparison of quarterly results without the impact of commodity price fluctuations from period to period which result in changes to the mark-to market value of the portfolio of commodity derivative contracts. Further, “Change in fair value of interest rate derivative contracts” does not include cash settlements paid on interest rate derivatives. Interest rate volatility can impact the mark-to-market value of these contracts, and commodity price volatility can also impact interest rate volatility. Any increase in the fair value of interest rate derivative contracts is reduced from Net Loss Attributable to Common and Class B Unitholders while any decrease in the fair value of interest rate derivative contracts is added back into Net
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Loss Attributable to Common and Class B Unitholders. Again, such adjustments are made to give investors a period to period comparison without showing the impact of non-cash gains or losses related to the mark-to-market valuation of these derivatives portfolios. In the future, in our explanation of the use of the non-GAAP measure “Adjusted Net Income,” we plan to clarify what is included in these adjustments. We also plan to provide a more fulsome explanation of the usefulness of such adjustments to our investors. In the future, we will also provide a reconciliation of the non-GAAP measure “Adjusted Net Income” with our earnings release.
*****
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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 or the Form 10-K or the Form 8-K to the 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 |
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| cc: | Richard Robert, Executive Vice President, Chief Financial Officer and Director, Vanguard Natural Resources, LLC |
Douglas V. Getten, Partner, Paul Hastings LLP
Ross Pilcik, Partner, BDO USA, LLP
