Exhibit 99.1
NEWS RELEASE
Vanguard Natural Resources Reports Fourth Quarter and Full Year 2014
Operating and Financial Results
HOUSTON-March 2, 2015--Vanguard Natural Resources, LLC (NASDAQ: VNR) ("Vanguard" or "the Company") today reported financial and operational results for the full year and fourth quarter ended December 31, 2014.
Mr. Scott W. Smith, President and CEO, commented, “We are pleased to have finished the year outperforming expectations and making good on our assertion that we would have over 1.0x distribution coverage for 2014 in spite of the collapse in the commodity markets in the fourth quarter. Our performance was bolstered by the acquisitions in 2014 which included over $1.4 billion invested in principally natural gas assets which should deliver sustainable cash flow for many years to come. With these transactions, the company achieved substantial growth in production, reserves and cash flow during the year. It’s a testament to the hard work of our talented employees that we successfully integrated these acquisitions with minimal disruptions to our base operations.
As we head into 2015, we have taken some difficult but necessary steps to position ourselves to live within our cash flow and provide us the opportunity to be active in the acquisition market during this low commodity price cycle. We believe Vanguard can compete effectively for quality assets which will drive our growth and provide substantial long-term benefits to our unitholders.”
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Selected Financial Information
A summary of selected financial information follows.
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| ($ in thousands, except per unit data) | ||||||||||||||||
| Production (Mcfe/d) | 402,164 | 221,415 | 327,109 | 212,686 | ||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 156,727 | $ | 108,319 | $ | 624,613 | $ | 443,248 | ||||||||
| Net gains (losses) on commodity derivative contracts | $ | 174,576 | $ | (350 | ) | $ | 163,452 | $ | 11,256 | |||||||
| Operating expenses | $ | 51,970 | $ | 39,507 | $ | 194,389 | $ | 145,932 | ||||||||
| Selling, general and administrative expenses | $ | 7,797 | $ | 6,763 | $ | 30,839 | $ | 25,942 | ||||||||
| Depreciation, depletion, amortization, and accretion | $ | 76,139 | $ | 44,181 | $ | 226,937 | $ | 167,535 | ||||||||
| Impairment of oil and natural gas properties | $ | 234,434 | $ | — | $ | 234,434 | $ | — | ||||||||
Net income (loss) available to Common and Class B Unitholders | $ | (66,828 | ) | $ | 870 | $ | 46,148 | $ | 56,877 | |||||||
Adjusted Net Income Available to Common and Class B Unitholders (1) | $ | 16,109 | $ | 10,922 | $ | 90,593 | $ | 69,513 | ||||||||
Adjusted Net Income Available to Common and Class B Unitholders, per unit (1) | $ | 0.19 | $ | 0.14 | $ | 1.10 | $ | 0.95 | ||||||||
Adjusted EBITDA(1) | $ | 125,647 | $ | 74,344 | $ | 421,445 | $ | 309,745 | ||||||||
| Interest expense, including settlements paid on interest rate derivatives | $ | 21,245 | $ | 15,907 | $ | 73,800 | $ | 65,036 | ||||||||
| Estimated maintenance capital expenditures | $ | 23,811 | $ | 14,469 | $ | 116,528 | $ | 56,661 | ||||||||
| Distributions to Preferred unitholders | $ | 6,690 | $ | 1,242 | $ | 18,197 | $ | 2,634 | ||||||||
Distributable Cash Flow Available to Common and Class B Unitholders (1) | $ | 73,901 | $ | 42,726 | $ | 214,870 | $ | 185,414 | ||||||||
Distributable Cash Flow per Common and Class B unit (1) | $ | 0.88 | $ | 0.55 | $ | 2.61 | $ | 2.48 | ||||||||
Common and Class B units distribution coverage (1) | 1.40x | 0.88x | 1.04x | 1.00x | ||||||||||||
| Weighted average common and Class B units outstanding at record date attributable to distribution period | 83,962 | 78,228 | 82,238 | 74,892 | ||||||||||||
| (1) | Non-GAAP financial measures. Please see Adjusted EBITDA and Distributable Cash Flow Available to Common and Class B Unitholders table at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure. Supplemental information on Vanguard's financial and operations results, including Adjusted Net Income Available to Common and Class B Unitholders, can be found under "Presentations" on the Investor Relations section of Vanguard’s corporate website, http://www.vnrllc.com. |
Fourth Quarter 2014 Highlights:
| • | Adjusted EBITDA (a non-GAAP financial measure defined below) increased 69% to $125.6 million from $74.3 million in the fourth quarter of 2013 and increased 16% compared to the $108.2 million recorded in the third quarter of 2014. |
| • | Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) increased 73% to $73.9 million compared to the $42.7 million generated in the fourth quarter of 2013 and increased 39% from the $53.0 million generated in the third quarter of 2014. |
| • | We reported a net loss for the quarter of $66.8 million or $(0.80) per basic unit after deducting distributions to Preferred unitholders compared to a reported net income of $0.9 million or $0.01 per basic unit in the fourth quarter of 2013. |
| • | Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $16.1 million in the fourth quarter of 2014, or $0.19 per basic unit, as compared to $10.9 million, or $0.14 per basic unit, in the fourth quarter of 2013. The recent quarter includes net non-cash expenses of $82.5 million that are adjustments to arrive at Adjusted |
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Net Income Available to Common and Class B Unitholders. The 2014 adjustments include a $234.4 million impairment charge on our oil and gas properties offset by a $155.9 million gain from the change in fair value of commodity derivative contracts. The fourth quarter of 2013 results include net non-cash expenses of $10.0 million.
| • | Reported average production of 402,164 Mcfe per day in the fourth quarter of 2014 was up 82% compared to 221,415 Mcfe per day produced in the fourth quarter of 2013 and a 25% increase compared to the third quarter of 2014. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 15%, 71%, and 14% of our production, respectively. |
Three Months Ended December 31, | Percentage Increase / (Decrease) | Three Months Ended September 30, | Percentage Increase / (Decrease) | |||||||||||||||
2014 (a) | 2013 (a) | 2014 (a) | ||||||||||||||||
| Total production volumes: | ||||||||||||||||||
| Oil (MBbls) | 907 | 773 | 17 | % | 813 | 12 | % | |||||||||||
| Natural Gas (MMcf) | 26,386 | 12,670 | 108 | % | 20,962 | 26 | % | |||||||||||
| NGLs (MBbls) | 862 | 511 | 69 | % | 629 | 37 | % | |||||||||||
| Combined (MMcfe) | 36,999 | 20,370 | 82 | % | 29,610 | 25 | % | |||||||||||
| Average realized prices, excluding hedges: | ||||||||||||||||||
| Oil (Price/Bbl) | $ | 63.39 | $ | 82.15 | (23 | )% | $ | 84.96 | (25 | )% | ||||||||
| Natural Gas (Price/Mcf) | $ | 3.19 | $ | 2.39 | 33 | % | $ | 3.24 | (2 | )% | ||||||||
| NGLs (Price/Bbl) | $ | 17.37 | $ | 28.45 | (39 | )% | $ | 26.66 | (35 | )% | ||||||||
Average realized prices, including hedges (b): | ||||||||||||||||||
| Oil (Price/Bbl) | $ | 78.97 | $ | 78.69 | — | % | $ | 84.36 | (6 | )% | ||||||||
| Natural Gas (Price/Mcf) | $ | 3.52 | $ | 3.41 | 3 | % | $ | 3.55 | (1 | )% | ||||||||
| NGLs (Price/Bbl) | $ | 18.22 | $ | 28.25 | (36 | )% | $ | 26.70 | (32 | )% | ||||||||
| Average NYMEX prices | ||||||||||||||||||
| Oil (Price/Bbl) | $ | 72.68 | $ | 97.50 | (25 | )% | $ | 97.13 | (25 | )% | ||||||||
| Natural Gas (Price/Mcf) | $ | 3.99 | $ | 3.60 | 11 | % | $ | 4.07 | (2 | )% | ||||||||
| (a) | During 2014 and 2013, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward. |
| (b) | Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. |
Full Year 2014 Highlights:
| • | Successfully closed $1.4 billion in acquisitions of natural gas and oil properties during the year ended December 31, 2014. |
| • | Adjusted EBITDA (a non-GAAP financial measure defined below) increased 36% to $421.4 million from the $309.7 million generated in 2013. |
| • | Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) increased 16% to $214.9 million from the $185.4 million generated in 2013. |
| • | We reported net income available to Common and Class B unitholders for the year ended December 31, 2014 of $46.1 million or $0.56 per basic unit compared to a net income of $56.9 million or $0.78 per basic unit in the year ended December 31, 2013. |
| • | Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $90.6 million in 2014, or $1.10 per unit, compared to $69.5 million, or $0.95 per unit, in 2013. The 2014 results include net non-cash losses of $43.7 |
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million that are adjustments to arrive at Adjusted Net Income Available to Common and Class B Unitholders. The 2014 adjustments include a $234.4 million impairment charge on our oil and gas properties offset by a $174.6 million gain from the change in fair value of commodity derivative contracts and a $34.5 million net gain on acquisitions of oil and gas properties. The 2013 results include non-cash losses of $11.8 million.
| • | Reported average production of 327,109 Mcfe per day in 2014 was up 54% compared to 212,686 Mcfe per day produced in 2013. On an Mcfe basis, crude oil, natural gas and natural gas liquids (“NGLs”) accounted for 16%, 70% and 14% of our production, respectively. |
| Year Ended December 31, | Percentage Increase / (Decrease) | ||||||||||
2014 (a) | 2013 (a) | ||||||||||
| Total production volumes: | |||||||||||
| Oil (MBbls) | 3,301 | 3,089 | 7 | % | |||||||
| Natural Gas (MMcf) | 83,037 | 50,236 | 65 | % | |||||||
| NGLs (MBbls) | 2,759 | 1,477 | 87 | % | |||||||
| Combined (MMcfe) | 119,395 | 77,630 | 54 | % | |||||||
| Average realized prices, excluding hedges: | |||||||||||
| Oil (Price/Bbl) | $ | 81.40 | $ | 87.06 | (7 | )% | |||||
| Natural Gas (Price/Mcf) | $ | 3.44 | $ | 2.48 | 39 | % | |||||
| NGLs (Price/Bbl) | $ | 25.55 | $ | 33.72 | (24 | )% | |||||
Average realized prices, including hedges (b): | |||||||||||
| Oil (Price/Bbl) | $ | 82.88 | $ | 82.26 | 1 | % | |||||
| Natural Gas (Price/Mcf) | $ | 3.50 | $ | 3.39 | 3 | % | |||||
| NGLs (Price/Bbl) | $ | 25.62 | $ | 33.76 | (24 | )% | |||||
| Average NYMEX prices | |||||||||||
| Oil (Price/Bbl) | $ | 92.21 | $ | 98.04 | (6 | )% | |||||
| Natural Gas (Price/Mcf) | $ | 4.39 | $ | 3.66 | 20 | % | |||||
| (a) | During 2014 and 2013, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward. |
| (b) | Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. |
Proved Reserves
Total estimated proved reserves at December 31, 2014 were 2,031.3 billion cubic feet equivalent, consisting of 92.5 million barrels of crude oil, condensate, and natural gas liquids and 1,475.9 billion cubic feet of natural gas. Proved reserves were calculated utilizing the 12-month unweighted average first-day-of-the-month prices ("12-month average prices") during 2014, or $94.87 per Bbl of oil and $4.36 per Mcf of natural gas as compared to $96.90 per Bbl of oil and $3.67 per Mcf of natural gas for 2013. Our proved reserves for the year ended December 31, 2014, included 148.9 Bcfe of negative revisions of previous estimates, due primarily to 95.7 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs primarily in the Arkoma basin as a result of a change in our development plan due to the lower commodity price environment and 41.6 Bcfe of negative revisions related to assumed ethane rejection in the Piceance Basin and Arkoma Basin. In addition, we had 23.0 Bcfe of negative revisions due to asset performance, partially offset by 11.4 Bcfe of positive revisions primarily due to higher natural gas prices as compared to the prior year. Negative revisions on estimated proved reserves due to ethane rejection did not have a significant impact on the standardized measure of discounted future net cash flows.
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Using the 12-month average prices, the estimated discounted net present value of Vanguard's proved oil and natural gas reserves, using a 10 percent per annum discount rate (“PV-10 Value”) was approximately $3.0 billion at December 31, 2014, as compared to a PV-10 Value of approximately $1.8 billion at December 31, 2013.
At December 31, 2014, natural gas reserves accounted for 73% of total proved reserves, and 68% of total proved reserves are developed. The following table summarizes the changes in proved reserves:
| Bcfe | |||
| Reserves at December 31, 2013 | 1,033.6 | ||
| Revisions of previous estimates due to PUD SEC 5-Year rule | (95.7 | ) | |
| Revisions of previous estimates due to ethane rejection | (41.6 | ) | |
| Performance revisions | (23.0 | ) | |
| Revisions of previous estimates due to price | 11.4 | ||
| Extensions, discoveries and other | 5.8 | ||
| Purchases of reserves in place | 1,274.6 | ||
| Sales of reserves-in-place | (14.4 | ) | |
| Production | (119.4 | ) | |
| Reserves at December 31, 2014 | 2,031.3 | ||
Vanguard's proved reserve estimates for all of its properties were prepared by its internal reservoir engineers and were audited by DeGolyer and MacNaughton (D&M), an independent third party engineering firm. D&M's audit covered properties representing 80.7% of Vanguard's total estimated proved reserves at year-end 2014.
Capital Expenditures
Capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $32.5 million in the fourth quarter of 2014 compared to $14.5 million for the comparable quarter of 2013 and $41.8 million for the third quarter of 2014. Estimated maintenance capital expenditures in the fourth quarter of 2014 totaled $23.8 million. The balance of $8.7 million was attributable to growth capital expenditures primarily associated with the Pinedale Acquisition in the Green River Basin during the fourth quarter of 2014. Total capital expenditures were approximately $142.0 million for the year ended December 31, 2014 compared to $56.7 million in the comparable period of 2013.
During 2015, we intend to concentrate our drilling on low risk, development opportunities with the majority of drilling capital focused on high Btu natural gas wells in two areas which we believe will continue to offer attractive drilling returns even in this low commodity price environment. We currently anticipate a capital budget for 2015 of approximately $113.5 million, excluding any potential future acquisitions, which is 20% less than our total spent in 2014. We expect to spend approximately 50% of the 2015 capital budget on activities in the Green River Basin where we will participate as a non-operated partner in the drilling and completion of vertical natural gas wells. Additionally, we expect to spend approximately 25% of the 2015 capital budget in the Gulf Coast Basin on the newly acquired East Haynesville assets drilling both vertical and horizontal wells and several recompletion projects. The balance of the 2015 budget is related to maintenance activities in our other operating areas. Due to our reduced capital spending in 2015 and the assumed ethane rejection beginning in 2015 on our assets acquired in the Pinedale Acquisition in the Green River Basin, we anticipate our annual production will be slightly lower than our fourth quarter 2014 average daily production of 402,164 Mcfe per day.
Hedging Activities
Recently, Vanguard has taken steps to restructure its hedge portfolio to limit further downside and volatility due to the current commodity price environment. Specifically, the Company has converted a significant portion of its three-way collars in 2015 to fixed-price swaps or lowered the pricing on existing short puts. We have implemented a hedging program for approximately 77% and 45% of our anticipated crude oil production in 2015 and 2016, respectively, with 88% in the form of fixed-price swaps in 2015. Approximately 82% and 67% of our natural gas
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production in 2015 and 2016, respectively, is hedged with 98% in the form of fixed-price swaps in 2015. NGLs production is under fixed-price swaps for approximately 9% of anticipated production in 2015.
| Year 2015 | Year 2016 | Year 2017 | |||||||||||
| Gas Production Hedged: | |||||||||||||
| % Anticipated Production Hedged | 82 | % | 67 | % | 40 | % | |||||||
| Weighted Average Price ($/MMBtu) | $ | 4.32 | $ | 4.37 | $ | 4.18 | |||||||
| Oil Production Hedged: | |||||||||||||
| % Anticipated Production Hedged | 77 | % | 45 | % | — | ||||||||
| Weighted Average Price ($/Bbl) | $ | 76.12 | $ | 83.02 | $ | — | |||||||
| NGLs Production Hedged: | |||||||||||||
| % Anticipated Production Hedged | 9 | % | — | — | |||||||||
| Weighted Average Price ($/Bbl) | $ | 46.34 | $ | — | $ | — | |||||||
For a summary of our current commodity derivative contracts, please refer to our Supplemental Presentation on the Investor Relations section of Vanguard’s corporate website, http://www.vnrllc.com.
Liquidity Update
At December 31, 2014 and February 27, 2015, Vanguard had indebtedness under its reserve-based credit facility totaling $1.36 billion with a borrowing base of $2.0 billion which provided for $634.5 million in undrawn capacity, after consideration of a $5.5 million reduction in availability for letters of credit. Absent new acquisitions, we expect that our borrowing base will be reduced at our next borrowing base redetermination which is scheduled for April 2015. The precise amount of the reduction is not known at this time but we do expect that we will have ample liquidity to manage our operations after the reduction.
In addition, we have been in discussions with certain banks in our credit facility regarding amending our debt to Adjusted EBITDA covenant during our next scheduled borrowing base redetermination. Based on those discussions, it is our expectation that the covenant will be changed to provide for more flexibility given lower forecasted Adjusted EBITDA due to the lower commodity price environment.
Cash Distributions
On February 17, 2015, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of January 2015 of $0.1175 per common and Class B unit, or $1.41 on an annualized basis, which will be paid on March 17, 2015 to Vanguard unitholders of record on March 2, 2015. This represents a reduction from the distribution attributable to the month of December 2014 of $0.21 per common and Class B unit, or $2.52 on an annualized basis.
Also on February 17, 2015, our board of directors declared and maintained a cash distribution for our preferred unitholders of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit which will be paid on March 16, 2015 to Vanguard preferred unitholders of record on March 2, 2015.
Annual Report on Form 10-K and Unitholders' Schedule K-1
Vanguard's financial statements and related footnotes will be available on our 2014 Form 10-K, which is expected to be filed today and will be available through the Investor Relations/SEC Filings section of the Vanguard's website at http://www.vnrllc.com.
Unitholders' Schedule K-1s for the tax year 2014 will be available for download on our website on or about March 5, 2015. For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1-866-536-1972 or via email at VanguardK1Help@deloitte.com.
Conference Call Information
Vanguard will host a conference call today to discuss its fourth quarter and full year 2014 results at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial (888) 510-1765 or (719) 457-2628 for international callers and ask for the “Vanguard Natural Resources Earnings Call.” The conference call will also be broadcast live via the Internet and can be accessed through the Investor Relations section of Vanguard's corporate website, http://www.vnrllc.com.
A telephonic replay of the conference call will be available until April 2, 2015 and may be accessed by calling (888) 203-1112 and using the pass code 9681939#. A webcast archive will be available on the Investor Relations page at www.vnrllc.com shortly after the call and will be accessible for approximately 30 days. For more information, please contact Lisa Godfrey at (832) 327-2234 or email at investorrelations@vnrllc.com.
About Vanguard Natural Resources, LLC
Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition, production and development of oil and natural gas properties. Vanguard's assets consist primarily of producing and non-producing oil and natural gas reserves located in the Green River Basin in Wyoming, the Arkoma Basin in Arkansas and Oklahoma, the Permian Basin in West Texas and New Mexico, the Big Horn Basin in Wyoming and Montana, the Piceance Basin in Colorado, the Gulf Coast Basin in Texas and Mississippi, the Williston Basin in North Dakota and Montana, the Wind River Basin in Wyoming and the Powder River Basin in Wyoming. More information on Vanguard can be found at www.vnrllc.com.
Forward-Looking Statements
This press release includes "forward-looking statements" within the meaning of the federal securities laws. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include but are not limited to statements about the acquisition announced in this press release. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for oil, natural gas and NGLs, our ability to replace reserves and efficiently develop our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company's reports filed with the Securities and Exchange Commission. Please see "Risk Factors" in the Company's public filings.
Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to publicly correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
Use of Non-GAAP Measures
Adjusted EBITDA
We present Adjusted EBITDA in addition to our reported net income (loss) in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) plus the following adjustments:
| • | Net interest expense; |
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| • | Depreciation, depletion, amortization, and accretion; |
| • | Impairment of oil and natural gas properties; |
| • | Net gains or losses on commodity derivative contracts; |
| • | Cash settlements on matured commodity derivative contracts; |
| • | Net gains or losses on interest rate derivative contracts; |
| • | Net gains and losses on acquisitions of oil and natural gas properties; |
| • | Texas margin taxes; |
| • | Compensation related items, which include unit-based compensation expense and unrealized fair value of phantom units granted to officers; and |
• | Transaction costs incurred on acquisitions. |
Adjusted EBITDA is a significant performance metric used by management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.
Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. For example, we fund premiums paid for derivative contracts, acquisitions of oil and natural gas properties, including the assumption of derivative contracts related to these acquisitions, and other capital expenditures primarily with proceeds from debt or equity offerings or with borrowings under our Reserve-Based Credit Facility. For the purposes of calculating Adjusted EBITDA, we consider the cost of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investments related to our underlying oil and natural gas properties; therefore, they are not deducted in arriving at our Adjusted EBITDA. Our Consolidated Statements of Cash Flows, prepared in accordance with GAAP, present cash settlements on matured derivatives and the initial cash outflows of premiums paid to enter into derivative contracts as operating activities. When we assume derivative contracts as part of a business combination, we allocate a part of the purchase price and assign them a fair value at the closing date of the acquisition. The fair value of the derivative contracts acquired is recorded as a derivative asset or liability and presented as cash used in investing activities in our Consolidated Statements of Cash Flows. As the volumes associated with these derivative contracts, whether we entered into them or we assumed them, are settled, the fair value is recognized in operating cash flows. Whether these cash settlements on derivatives are received or paid, they are reported as operating cash flows which may increase or decrease the amount we have available to fund distributions.
As noted above, for purposes of calculating Adjusted EBITDA, we consider both premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities. This is similar to the way the initial acquisition or development costs of our oil and natural gas properties are presented in our Consolidated Statements of Cash Flows; the initial cash outflows are presented as cash used in investing activities, while the cash flows generated from these assets are included in operating cash flows. The consideration of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities for purposes of determining our Adjusted EBITDA differs from the presentation in our consolidated financial statements prepared in accordance with GAAP which (i) presents premiums paid for derivatives entered into as
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operating activities and (ii) the fair value of derivative contracts acquired as part of a business combination as investing activities.
Distributable Cash Flow Available to Common and Class B Unitholders
We present Distributable Cash Flow Available to Common and Class B Unitholders in addition to our reported net income (loss) in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a non-GAAP financial measure that is defined as net income (loss) plus the following adjustments:
| • | Depreciation, depletion, amortization, and accretion; |
• | Impairment of oil and natural gas properties; |
| • | Net gains or losses on commodity derivative contracts; |
| • | Cash settlements on matured commodity derivative contracts; |
•Net gains and losses on acquisitions of oil and natural gas properties;
| • | Texas margin taxes; |
| • | Compensation related items, which include unit-based compensation expense and unrealized fair value on phantom units granted to officers; and |
• | Transaction costs incurred on acquisitions; |
Less:
•Drilling, capital workover and recompletion expenditures;
•Distributions to Preferred unitholders;
Plus:
•Proceeds from the sale of leasehold interests.
Distributable Cash Flow Available to Common and Class B Unitholders is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our monthly distribution rates. However, Distributable Cash Flow Available to Common and Class B Unitholders should not be viewed as indicative of the amount that we plan to distribute for a given period. Distributable Cash Flow Available to Common and Class B Unitholders is not intended to be a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a metric commonly used by investors and the analyst community to assess our financial performance from period to period.
The amount of cash that we have available for distribution depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our GAAP net income, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may be able to pay distributions during periods when we incur net losses. Our board of directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of our limited liability company agreement. Management considers the timing and size of capital expenditures and long-term views about expected results in determining the amount of distributions. Capital spending and the resulting production and net cash provided by
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operating activities do not typically occur evenly throughout the year due to a variety of factors which are difficult to predict, including rig availability, weather, well performance, the timing of completions and the commodity price environment. Consistent with practices common to publicly traded partnerships, our board of directors historically has not varied the distribution it declares period to period based on uneven available distributable cash flow. Our board of directors reviews historical financial results and forecasts for future periods, including development activities, as well as considers the impact of significant acquisitions in making a determination to increase, decrease or maintain the current level of distribution. In instances following acquisitions and development activities, our board of directors reviews any excess in distributable cash flows after distributions to unitholders in those periods, as well as forecasts of expected future net cash flows to determine if increases in distributions could be made. If shortfalls are sustained over time and forecasts demonstrate expectations for continued future shortfalls, our board of directors may determine to reduce, suspend or discontinue paying distributions. Our board of directors may decide to retain the excess in distributable cash flows after distributions to unitholders for our future operations, future capital expenditures, future debt service or other future obligations. Any shortfalls are funded with cash on hand and/or with borrowings under our reserve-based credit facility.
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) to Adjusted EBITDA (a) and
Distributable Cash Flow Available to Common and Class B Unitholders
(Unaudited)
(in thousands, except per unit amounts)
Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Net income (loss) | $ | (60,138 | ) | $ | 2,112 | $ | 64,345 | $ | 59,511 | |||||||
| Plus: | ||||||||||||||||
| Interest expense | 20,236 | 14,915 | 69,765 | 61,148 | ||||||||||||
| Depreciation, depletion, amortization and accretion | 76,139 | 44,181 | 226,937 | 167,535 | ||||||||||||
| Impairment of oil and natural gas properties | 234,434 | — | 234,434 | — | ||||||||||||
| Net (gains) losses on commodity derivative contracts | (174,577 | ) | 350 | (163,452 | ) | (11,256 | ) | |||||||||
Cash settlements on matured commodity derivative contracts (b)(c) | 23,534 | 10,043 | 10,187 | 30,905 | ||||||||||||
Net losses on interest rate derivative contracts (d) | 865 | 494 | 1,933 | 96 | ||||||||||||
| Net gains on acquisitions of oil and natural gas properties | — | — | (34,523 | ) | (5,591 | ) | ||||||||||
| Texas margin taxes | (505 | ) | 741 | (630 | ) | 601 | ||||||||||
| Compensation related items | 5,270 | 1,486 | 11,710 | 5,931 | ||||||||||||
| Transaction costs incurred on acquisitions | 389 | 22 | 739 | 865 | ||||||||||||
| Adjusted EBITDA | $ | 125,647 | $ | 74,344 | $ | 421,445 | $ | 309,745 | ||||||||
| Less: | ||||||||||||||||
| Interest expense, including settlements paid on interest rate derivatives | (21,245 | ) | (15,907 | ) | (73,800 | ) | (65,036 | ) | ||||||||
Estimated maintenance capital expenditures (e) | (23,811 | ) | (14,469 | ) | (116,528 | ) | (56,661 | ) | ||||||||
| Distributions to Preferred unitholders | (6,690 | ) | (1,242 | ) | (18,197 | ) | (2,634 | ) | ||||||||
| Proceeds from sale of leasehold interests | — | — | 1,950 | — | ||||||||||||
| Distributable Cash Flow Available to Common and Class B unitholders | $ | 73,901 | $ | 42,726 | $ | 214,870 | $ | 185,414 | ||||||||
| Distributions to Common and Class B unitholders | 52,896 | 48,697 | 207,035 | 184,796 | ||||||||||||
| Excess (shortfall) of distributable cash flow after distributions to unitholders | $ | 21,005 | $ | (5,971 | ) | $ | 7,835 | $ | 618 | |||||||
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| Distributable Cash Flow per Common and Class B unit | $ | 0.88 | $ | 0.55 | $ | 2.61 | $ | 2.48 | ||||||||
| Common and Class B unit Distribution Coverage | 1.40x | 0.88x | 1.04x | 1.00x | ||||||||||||
| (a) Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. | ||||||||||||||||
| (b) Excludes premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We consider the cost of premiums paid for derivatives as an investment related to our underlying oil and natural gas properties. | $ | — | $ | 55 | $ | — | $ | 220 | ||||||||
| (c) Excludes the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. We consider the amounts paid to sellers for derivative contracts assumed with business combinations a part of the purchase price of the underlying oil and natural gas properties. | $ | 4,834 | $ | 7,328 | $ | 21,306 | $ | 30,200 | ||||||||
| (d) Includes settlements paid on interest rate derivatives | $ | 1,009 | $ | 992 | $ | 4,035 | $ | 3,888 | ||||||||
(e) Estimated maintenance capital expenditures are intended to represent the amount of capital required to offset the decrease in cash flow from the prior year due to the change in natural gas, oil and NGLs prices and the decline in proved developed producing production. These costs, which are incorporated in our annual capital budget as approved by the board of directors, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing cash flow on both operated and non-operated properties. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our cash flow. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain cash flow at current levels, which could adversely affect our ability to pay a distribution at the current level or at all. | ||||||||||||||||
SOURCE: Vanguard Natural Resources, LLC
CONTACT: Vanguard Natural Resources, LLC
Investor Relations
Lisa Godfrey, 832-327-2234
investorrelations@vnrllc.com
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