HOUSTON, Nov. 09, 2015 (GLOBE NEWSWIRE) -- Vanguard Natural Resources, LLC (NASDAQ:VNR) (“Vanguard” or “the Company”) today reported financial and operational results for the quarter ended September 30, 2015.
Mr. Scott W. Smith, President and CEO, commented, “We are very pleased to have closed the LRR Energy LP (“LRE”) and Eagle Rock Energy Partners, LP (“EROC”) mergers in the first week of October. It goes without saying that consummating two mergers at the same time posed a challenge for the company. Our team has done a tremendous job throughout this process and the integration of both sets of assets has gone extremely well due to the efforts of our employees. With these two transactions, our daily production will increase approximately 33% to 513 mmcfe/d and our reserves will increase approximately 28% to 2.4 Tcfe as of September 30, 2015. Additionally, we issued approximately 43.7 million units in these transactions and welcome the former LRE and EROC unitholders to VNR.
We are pleased with our results this quarter as we saw an increase in our daily production while at the same time spending considerable less capex than originally forecast. Our assets continue to perform well and our operating teams and our drilling partners continue to deliver lower operating costs and gain efficiencies in this low commodity price environment. Our focus for the balance of the year will be continuing this trend and we are looking forward to reporting the impact to the Company from the contribution of the LRR and EROC assets in the fourth quarter and beyond.”
Selected Financial Information
A summary of selected financial information follows:
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| ($ in thousands, except per unit data) (Unaudited) | ||||||||||||||||
| Production (Mcfe/d) | 386,679 | 321,847 | 383,067 | 301,816 | ||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 90,827 | $ | 153,627 | $ | 285,562 | $ | 467,886 | ||||||||
| Net gains (losses) on commodity derivative contracts | $ | 64,328 | $ | 83,311 | $ | 102,561 | $ | (11,125 | ) | |||||||
| Operating expenses | $ | 43,251 | $ | 46,141 | $ | 132,509 | $ | 142,419 | ||||||||
| Selling, general and administrative expenses | $ | 8,046 | $ | 7,140 | $ | 26,239 | $ | 23,042 | ||||||||
| Depreciation, depletion, amortization, and accretion | $ | 52,428 | $ | 55,680 | $ | 182,443 | $ | 150,798 | ||||||||
| Impairment of oil and natural gas properties | $ | 491,487 | $ | — | $ | 1,357,462 | $ | — | ||||||||
| Net income (loss) attributable to Common and Class B unitholders | $ | (468,967 | ) | $ | 109,150 | $ | (1,394,822 | ) | $ | 112,975 | ||||||
| Adjusted Net Income Attributable to Common and Class B Unitholders (1) | $ | 1,606 | $ | 27,916 | $ | 12,995 | $ | 74,483 | ||||||||
| Adjusted Net Income Attributable to Common and Class B Unitholders, per unit (1) | $ | 0.02 | $ | 0.34 | $ | 0.15 | $ | 0.92 | ||||||||
| Adjusted EBITDA(1) | $ | 88,204 | $ | 108,245 | $ | 264,122 | $ | 295,796 | ||||||||
| Interest expense, including settlements paid on interest rate derivative contracts | $ | 22,118 | $ | 17,742 | $ | 64,661 | $ | 52,555 | ||||||||
| Estimated maintenance capital expenditures | $ | 28,113 | $ | 32,566 | $ | 80,213 | $ | 92,716 | ||||||||
| Distributions to Preferred unitholders | $ | 6,690 | $ | 4,949 | $ | 20,070 | $ | 11,507 | ||||||||
| Distributable Cash Flow Available to Common and Class B Unitholders (1) | $ | 31,283 | $ | 52,988 | $ | 99,178 | $ | 140,968 | ||||||||
| Distributable Cash Flow per common and Class B unit (1) | $ | 0.36 | $ | 0.63 | $ | 1.15 | $ | 1.73 | ||||||||
| Common and Class B unit distribution coverage (1) | 1.02x | 1.00x | 1.09x | 0.91x | ||||||||||||
| Weighted average common and Class B units outstanding at record date attributable to distribution period | 87,018 | 83,768 | 86,009 | 81,663 | ||||||||||||
(1) Non-GAAP financial measures. Please see Adjusted EBITDA and Distributable Cash Flow Available to Common and Class B Unitholders tables 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.
Third Quarter 2015 Highlights:
- Adjusted EBITDA (a non-GAAP financial measure defined below) decreased 19% to $88.2 million in the third quarter of 2015 from $108.2 million in the third quarter of 2014 and decreased 3% from the $90.6 million recorded in the second quarter of 2015.
- Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) decreased 41% to $31.3 million from the $53.0 million generated in the third quarter of 2014 and decreased 12% from the $35.5 million generated in the second quarter of 2015.
- 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 $1.6 million in the third quarter of 2015, or $0.02 per basic unit, as compared to Adjusted Net Income of $27.9 million, or $0.34 per basic unit, in the third quarter of 2014 and Adjusted Net Loss of $6.6 million, or $0.07 per basic unit, in the second quarter of 2015. The third quarter of 2015 includes net non-cash losses of $470.6 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The third quarter 2015 adjustments include a $491.5 million impairment charge on our oil and natural gas properties. The third quarter of 2014 results included net non-cash gains of $81.6 million primarily attributable to the change in fair value of commodity derivative contracts.
| Three Months Ended September 30, | Percentage Increase / (Decrease) | Three Months Ended June 30, | Percentage Increase / (Decrease) | |||||||||||||||
| 2015 (a) | 2014 (a) | 2015 | ||||||||||||||||
| Total production volumes: | ||||||||||||||||||
| Oil (MBbls) | 839 | 813 | 3 | % | 866 | (3 | )% | |||||||||||
| Natural Gas (MMcf) | 26,242 | 20,962 | 25 | % | 23,543 | 11 | % | |||||||||||
| NGLs (MBbls) | 717 | 629 | 14 | % | 796 | (10 | )% | |||||||||||
| Combined (MMcfe) | 35,574 | 29,610 | 20 | % | 33,514 | 6 | % | |||||||||||
| Average daily production volumes: | ||||||||||||||||||
| Oil (Bbls/day) | 9,115 | 8,832 | 3 | % | 9,511 | (3 | )% | |||||||||||
| Natural Gas (Mcf/day) | 285,236 | 227,850 | 25 | % | 258,720 | 11 | % | |||||||||||
| NGLs (Bbls/day) | 7,792 | 6,835 | 14 | % | 8,751 | (10 | )% | |||||||||||
| Combined (Mcfe/day) | 386,679 | 321,847 | 20 | % | 368,290 | 6 | % | |||||||||||
| Average NYMEX prices: | ||||||||||||||||||
| Oil (Price/Bbl) | $ | 46.39 | $ | 97.13 | (52 | )% | $ | 57.94 | (20 | )% | ||||||||
| Natural Gas (Price/Mcf) | $ | 2.77 | $ | 4.07 | (32 | )% | $ | 2.63 | 5 | % | ||||||||
| Average realized prices, excluding hedges: | ||||||||||||||||||
| Oil (Price/Bbl) | $ | 40.10 | $ | 84.96 | (53 | )% | $ | 50.85 | (21 | )% | ||||||||
| Natural Gas (Price/Mcf) | $ | 1.94 | $ | 3.24 | (40 | )% | $ | 1.69 | 15 | % | ||||||||
| NGLs (Price/Bbl) | $ | 8.86 | $ | 26.66 | (67 | )% | $ | 14.98 | (41 | )% | ||||||||
| Average realized prices, including hedges (b): | ||||||||||||||||||
| Oil (Price/Bbl) | $ | 53.66 | $ | 84.36 | (36 | )% | $ | 58.02 | (8 | )% | ||||||||
| Natural Gas (Price/Mcf) | $ | 3.17 | $ | 3.55 | (11 | )% | $ | 3.16 | — | % | ||||||||
| NGLs (Price/Bbl) | $ | 11.23 | $ | 26.70 | (58 | )% | $ | 16.93 | (34 | )% | ||||||||
(a) During 2015 and 2014, 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.
2015 Nine Month Highlights:
- Adjusted EBITDA (a non-GAAP financial measure defined below) decreased 11% to $264.1 million in the first nine months of 2015 from $295.8 million in the first nine months of 2014.
- Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) for the first nine months of 2015 decreased 30% to $99.2 million from the $141.0 million generated in the first nine months of 2014.
- Adjusted Net Income Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $13.0 million for the first nine months of 2015, or $0.15 per basic unit, as compared to $74.5 million, or $0.92 per basic unit, in the comparable period of 2014. The first nine months of 2015 includes net non-cash losses of $1.4 billion that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The net non-cash losses primarily resulted from a $1.4 billion impairment charge on our oil and natural gas properties. Results for the first nine months of 2014 included net non-cash gains of $38.8 million primarily attributable to net gains on acquisitions of oil and natural gas properties recognized during the period.
| Nine Months Ended September 30, | Percentage Increase / (Decrease) | ||||||||||
| 2015 (a) | 2014 (a) | ||||||||||
| Total production volumes: | |||||||||||
| Oil (MBbls) | 2,554 | 2,394 | 7 | % | |||||||
| Natural Gas (MMcf) | 76,645 | 56,651 | 35 | % | |||||||
| NGLs (MBbls) | 2,102 | 1,897 | 11 | % | |||||||
| Combined (MMcfe) | 104,577 | 82,396 | 27 | % | |||||||
| Average daily production volumes: | |||||||||||
| Oil (Bbls/day) | 9,355 | 8,769 | 7 | % | |||||||
| Natural Gas (Mcf/day) | 280,751 | 207,512 | 35 | % | |||||||
| NGLs (Bbls/day) | 7,698 | 6,949 | 11 | % | |||||||
| Combined (Mcfe/day) | 383,067 | 301,816 | 27 | % | |||||||
| Average NYMEX prices: | |||||||||||
| Oil (Price/Bbl) | $ | 51.04 | $ | 99.62 | (49 | )% | |||||
| Natural Gas (Price/Mcf) | $ | 2.80 | $ | 4.57 | (39 | )% | |||||
| Average realized prices, excluding hedges: | |||||||||||
| Oil (Price/Bbl) | $ | 44.41 | $ | 88.23 | (50 | )% | |||||
| Natural Gas (Price/Mcf) | $ | 1.91 | $ | 3.55 | (46 | )% | |||||
| NGLs (Price/Bbl) | $ | 12.20 | $ | 29.26 | (58 | )% | |||||
| Average realized prices, including hedges (b): | |||||||||||
| Oil (Price/Bbl) | $ | 55.49 | $ | 84.36 | (34 | )% | |||||
| Natural Gas (Price/Mcf) | $ | 3.13 | $ | 3.49 | (10 | )% | |||||
| NGLs (Price/Bbl) | $ | 14.38 | $ | 28.98 | (50 | )% | |||||
(a) During 2015 and 2014, 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.
Capital Expenditures
Total capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $28.1 million in the third quarter of 2015 compared to $41.8 million for the comparable quarter of 2014 and $27.0 million for the second quarter of 2015. Capital spending in the third quarter of 2015 included only maintenance capital expenditures. For the third quarter of 2014, capital spending included maintenance capital expenditures of approximately $32.6 million and growth capital expenditures of $9.2 million primarily associated with the Pinedale acquisition in the Green River Basin. Total capital expenditures were approximately $80.2 million for the first nine months of 2015 compared to $109.5 million for the first nine months of 2014.
We currently anticipate a total capital expenditures budget for the remainder of 2015 to range between $31.0 million and $34.0 million, excluding any potential future acquisitions. We expect to spend approximately 51% ($16.0 million to $17.5 million) participating as a non-operated partner drilling and completing horizontal wells in the SCOOP and STACK plays in the Anadarko Basin acquired in the EROC merger. Additionally, we expect to spend approximately 22% ($7.1 million to $7.5 million) of the remaining 2015 capital budget in the Green River Basin where we will participate as a non-operated partner in the drilling and completion of vertical and directional natural gas wells and approximately 7% ($2.0 million to $2.2 million) in the Gulf Coast Basin on completion and seismic activities in the East Haynesville field. The balance of the remaining 2015 budget ($5.9 million to $6.8 million) is related to maintenance activities in our other operating areas including approximately $1.3 million to $1.5 million of capital workovers associated with assets acquired in the LRE merger.
Recent Activities
Mergers
LRE Merger
On October 5, 2015, Vanguard completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), pursuant to which a subsidiary of Vanguard merged into LRR Energy, L.P. (“LRE”) and, at the same time, Vanguard acquired LRE GP, LLC (the “LRE GP”), the general partner of LRR Energy, L.P. (the “LRE Merger”).
Under the terms of the LRE Merger Agreement, (i) each outstanding LRE common unit was converted into the right to receive 0.550 newly issued Vanguard common units and (ii) Vanguard purchased all of the outstanding limited liability company interests in LRE GP in exchange for 12,320 newly issued Vanguard common units. Further, in connection with the LRE Merger Agreement, each award of restricted LRE common units issued under LRE’s long-term incentive plan that was subject to time-based vesting and that was outstanding and unvested immediately prior to the effective time of the LRE Merger became fully vested and was deemed to be a LRE common unit with the right to receive Vanguard common units.
As consideration for the LRE Merger, Vanguard issued approximately 15.4 million common units valued at $121.3 million based on the closing price per Vanguard common unit of $7.86 at October 5, 2015 and assumed $290.0 million in debt.
The LRE Merger was completed following approval, at a Special Meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding LRE Common Units.
The LRE Merger increased Vanguard’s proved reserves by approximately 145 Bcfe as of the merger date and is expected to bring additional production of 42 MMcfe per day increasing Vanguard’s production by approximately 11% based on Vanguard’s third quarter 2015 average daily production.
Eagle Rock Merger
On October 8, 2015, Vanguard completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”) pursuant to which Eagle Rock Energy Partners, L.P. became a wholly-owned indirect subsidiary of Vanguard (the “Eagle Rock Merger”).
Under the terms of the Eagle Rock Merger Agreement, (i) each Eagle Rock common unit was converted into the right to receive 0.185 newly issued Vanguard common units. Further, in connection with the Eagle Rock Merger Agreement, Vanguard adopted Eagle Rock’s long-term incentive plan and each outstanding award of Eagle Rock common units issued under such plan was converted into a new award of restricted units based on Vanguard common units. However, any outstanding Eagle Rock common units held by employees and officers of Eagle Rock and members of the board of directors of Eagle Rock who did not receive employment offers from Vanguard accelerated upon the effective time of the Eagle Rock Merger and was converted into the right to receive newly issued Vanguard common units, with the vesting of performance-based restricted units determined based upon Eagle Rock’s actual performance through the effective time of the Eagle Rock Merger (subject to Vanguard’s good faith review).
As consideration for the Eagle Rock Merger, Vanguard issued approximately 28.3 million Vanguard common units valued at $259.2 million based on the closing price per Vanguard common unit of $9.17 at October 8, 2015 and assumed $151.8 million in debt.
The Eagle Rock Merger was completed following (i) approval by holders of a majority of the outstanding Eagle Rock common units, at a Special Meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of Unitholders, of the issuance of Vanguard common units to be issued as Eagle Rock Merger Consideration to the holders of Eagle Rock common units in connection with the Eagle Rock Merger.
The Eagle Rock Merger increased Vanguard’s proved reserves by approximately 387 Bcfe as of the merger date and is expected to bring additional production of 84 MMcfe per day increasing Vanguard’s production by approximately 22% based on Vanguard’s third quarter 2015 average daily production. The assets acquired from this transaction add scale in Vanguard’s existing Gulf Coast and Permian Basins and establish a new operating platform in the SCOOP/STACK play in the Anadarko basin.
Hedging Activities
We have implemented a hedging program for approximately 79% and 50% of our anticipated crude oil production in 2015 and 2016, respectively, with 84% in the form of fixed-price swaps for the balance of 2015. Approximately 88% and 68% of our natural gas production in 2015 and 2016, respectively, is hedged with 100% in the form of fixed-price swaps for the balance of 2015. NGLs production is hedged using fixed-price swaps for approximately 9% and 21% of anticipated production for the balance of 2015 and 2016, respectively. Our hedge position as of September 30, 2015, excluding the impact of the LRE Merger and Eagle Rock Merger discussed above, is shown below.
| October 1 - December 31, 2015 | Year 2016 | Year 2017 | ||||||||||
| Gas Production Hedged: | ||||||||||||
| % Anticipated Production Hedged | 88 | % | 68 | % | 41 | % | ||||||
| Weighted Average Price ($/MMBtu) | $ | 4.26 | $ | 4.37 | $ | 4.18 | ||||||
| Oil Production Hedged: | ||||||||||||
| % Anticipated Production Hedged | 79 | % | 50 | % | — | % | ||||||
| Weighted Average Price ($/Bbl) | $ | 72.27 | $ | 81.14 | $ | — | ||||||
| NGLs Production Hedged: | ||||||||||||
| % Anticipated Production Hedged | 9 | % | 21 | % | — | % | ||||||
| Weighted Average Price ($/Bbl) | $ | 46.34 | $ | 29.96 | $ | — | ||||||
The impact of the LRE Merger and Eagle Rock Merger on our future hedge position is included in the amounts and percentages shown below.
| October 1 - December 31, 2015 | Year 2016 | Year 2017 | ||||||||||
| Gas Production Hedged: | ||||||||||||
| % Anticipated Production Hedged | 85 | % | 69 | % | 39 | % | ||||||
| Weighted Average Price ($/MMBtu) | $ | 4.31 | $ | 4.35 | $ | 4.19 | ||||||
| Oil Production Hedged: | ||||||||||||
| % Anticipated Production Hedged | 78 | % | 59 | % | 17 | % | ||||||
| Weighted Average Price ($/Bbl) | $ | 79.64 | $ | 83.27 | $ | 86.71 | ||||||
| NGLs Production Hedged: | ||||||||||||
| % Anticipated Production Hedged | 24 | % | 21 | % | — | % | ||||||
| Weighted Average Price ($/Bbl) | $ | 34.13 | $ | 30.31 | $ | — | ||||||
For a summary of all commodity and interest rate derivative contracts in place at September 30, 2015, please refer to our Quarterly Report on Form 10-Q which will be filed today, November 9, 2015.
At September 30, 2015, the fair value of commodity derivative contracts, excluding the impact of the LRE Merger and Eagle Rock Merger discussed above, was an asset of approximately $205.7 million, of which $142.3 million settles during the next twelve months. The commodity derivative contracts acquired in the LRE Merger and Eagle Rock Merger have a combined fair value of $188.3 million at September 30, 2015. Currently, we use fixed-price swaps, puts, basis swap contracts, three-way collars, swaptions, call options sold, put options sold and range bonus accumulators to hedge oil, natural gas and NGLs prices.
Liquidity Update
Credit Facility
On November 6, 2015, we completed our semi-annual borrowing base redetermination and entered into the Fourth Amended and Restated Credit Agreement (“Restated Credit Agreement”), which reaffirms the Company’s $1.8 billion borrowing base. The terms of the Restated Credit Agreement also include, among other provisions, the increase in the maximum investments or capital contributions that can be made in certain entities from $5.0 million to $100.0 million. In addition, the Company is permitted to incur up to $300.0 million of junior lien indebtedness provided the borrowing base will be reduced by $0.25 cents for every dollar of junior debt issued.
As of today, November 9, 2015, there was $1.69 billion of outstanding borrowings and $105.5 million of borrowing capacity under the reserve-based credit facility, after consideration of a $4.5 million reduction in availability for letters of credit and a $1.8 billion borrowing base. We also have approximately $10.0 million in available cash.
At-The-Market (“ATM”) Equity Program
Total net proceeds received under our At-The-Market (“ATM”) Equity Program were approximately $12.2 million, $20.5 million and $2.8 million, after commissions and fees, for the first, second and third quarters of 2015, respectively. In total for 2015, we have raised net proceeds of $35.5 million, after commissions and fees, from the sales of 2,430,170 common units.
Cash Distributions
On October 19, 2015, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of September 2015 of $0.1175 per common and Class B unit ($1.41 on an annualized basis) expected to be paid on November 13, 2015 to Vanguard unitholders of record on November 2, 2015, which includes unitholders who received the newly issued Vanguard common units as part of the LRE Merger and Eagle Rock Merger.
Also on October 19, 2015, our board of directors declared 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 to be paid on November 13, 2015 to Vanguard preferred unitholders of record on November 2, 2015.
Conference Call Information
Vanguard will host a conference call on Monday, November 9, 2015, to discuss its third quarter 2015 financial results, at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial 1-887-587-0615 or 719-457-2627, for international callers, using access code 9741066 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 December 9, 2015 and may be accessed by calling 1-888-203-1112 or 719-457-0820, for international callers, and using access code 9741066. 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 Piceance Basin in Colorado, the Permian Basin in West Texas and New Mexico, the Gulf Coast Basin in Texas, Louisiana and Mississippi, the Big Horn Basin in Wyoming and Montana, the Arkoma Basin in Arkansas and Oklahoma, 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.
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;
- 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 (losses) on acquisitions of oil and natural gas properties;
- Texas margin taxes;
- Compensation related items, which include unit-based compensation expense, unrealized fair value of phantom units granted to officers and cash settlement of phantom units granted to officers; and
- Material 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 (loss), 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 (loss) 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 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:
- Net interest expense;
- 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 (losses) on acquisitions of oil and natural gas properties;
- Texas margin taxes;
- Compensation related items, which include unit-based compensation expense, unrealized fair value of phantom units granted to officers and cash settlement of phantom units granted to officers; and
- Material transaction costs incurred on acquisitions;
Less:
- Estimated maintenance capital expenditures;
- Distributions to Preferred unitholders.
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 (loss), 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 (loss), 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 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 | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Net income (loss) | $ | (462,277 | ) | $ | 114,099 | $ | (1,374,752 | ) | $ | 124,482 | ||||||
| Plus: | ||||||||||||||||
| Interest expense | 21,130 | 16,721 | 61,693 | 49,529 | ||||||||||||
| Depreciation, depletion, amortization, and accretion | 52,428 | 55,680 | 182,443 | 150,798 | ||||||||||||
| Impairment of oil and natural gas properties | 491,487 | — | 1,357,462 | — | ||||||||||||
| Net (gains) losses on commodity derivative contracts | (64,328 | ) | (83,311 | ) | (102,561 | ) | 11,125 | |||||||||
| Net cash settlements received (paid) on matured commodity derivative contracts (a)(b)(c) | 45,368 | 6,033 | 125,988 | (13,347 | ) | |||||||||||
| Net (gains) losses on interest rate derivative contracts (d) | 807 | (511 | ) | 2,291 | 1,068 | |||||||||||
| Net (gains) losses on acquisitions of oil and natural gas properties | 284 | (2,409 | ) | 284 | (34,523 | ) | ||||||||||
| Texas margin taxes | (522 | ) | 156 | (380 | ) | (125 | ) | |||||||||
| Compensation related items | 3,827 | 1,438 | 11,654 | 6,440 | ||||||||||||
| Material transaction costs incurred on acquisitions | — | 349 | — | 349 | ||||||||||||
| Adjusted EBITDA | $ | 88,204 | $ | 108,245 | $ | 264,122 | $ | 295,796 | ||||||||
| Less: | ||||||||||||||||
| Interest expense, including settlements paid on interest rate derivatives | (22,118 | ) | (17,742 | ) | (64,661 | ) | (52,555 | ) | ||||||||
| Estimated maintenance capital expenditures (f) | (28,113 | ) | (32,566 | ) | (80,213 | ) | (92,716 | ) | ||||||||
| Distributions to Preferred unitholders | (6,690 | ) | (4,949 | ) | (20,070 | ) | (11,507 | ) | ||||||||
| Proceeds from sale of leasehold interests | — | — | — | 1,950 | ||||||||||||
| Distributable Cash Flow Available to Common and Class B Unitholders | $ | 31,283 | $ | 52,988 | $ | 99,178 | $ | 140,968 | ||||||||
| Distributions to Common and Class B unitholders | 30,674 | 52,774 | 90,955 | 154,139 | ||||||||||||
| Excess (shortfall) of distributable cash flow after distributions to unitholders | $ | 609 | $ | 214 | $ | 8,223 | $ | (13,171 | ) | |||||||
| Distributable Cash Flow per Common and Class B unit | $ | 0.36 | $ | 0.63 | $ | 1.15 | $ | 1.73 | ||||||||
| Common and Class B unit Distribution Coverage | 1.02x | 1.00x | 1.09x | 0.91x | ||||||||||||
| (a) Our Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income (loss), 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 (loss) and operating income (loss) 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. | $ | 2,057 | $ | — | $ | 4,624 | $ | — | ||||||||
| (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. Also excludes the fair value of derivative contracts acquired and settled during the period. | $ | 12,453 | $ | 5,608 | $ | 32,734 | $ | 16,472 | ||||||||
| (d) Excludes fair value of restructured derivative contracts. | $ | — | $ | — | $ | (31,945 | ) | $ | — | |||||||
| (e) Includes settlements paid on interest rate derivatives. | $ | 988 | $ | 1,021 | $ | 2,968 | $ | 3,026 | ||||||||
| (f) Estimated maintenance capital expenditures are intended to represent the amount of capital required to offset the decrease in production from the prior year due to 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 production from 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 production. 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 production at current levels, which could adversely affect our ability to pay a distribution at the current level or at all. | ||||||||||||||||