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Vanguard Natural Resources, LLC Reports Second Quarter 2015 Results

HOUSTON, Aug. 3, 2015 (GLOBE NEWSWIRE) -- Vanguard Natural Resources, LLC (NASDAQ:VNR) ("Vanguard" or "the Company") today reported financial and operational results for the quarter ended June 30, 2015.

Mr. Scott W. Smith, President and CEO, commented, "In spite of another challenging quarter on the commodity price front, we are pleased to report what we think are solid second quarter results. Our production volumes while below our first quarter results were in line with our expectations and are a testament to our asset base of quality, long life reserves. Our operating teams focus on driving lease operating costs lower are continuing to bear fruit and reflects their hard work in the field. We are making progress on both the LRR Energy, L.P. (NYSE:LRE) and Eagle Rock Energy Partners, L.P. (NASDAQ:EROC) mergers and we look forward to closing both of these transactions by the end of the third quarter."

Selected Financial Information

A summary of selected financial information follows:

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
($ in thousands, except per unit data)
(Unaudited)
Production (MMcfe/d) 368 315 381 292
Oil, natural gas and natural gas liquids sales $ 95,841 $ 161,519 $ 194,735 $ 314,259
Net gains (losses) on commodity derivative contracts $ (20,800) $ (38,398) $ 38,233 $ (94,436)
Operating expenses $ 42,354 $ 50,822 $ 89,258 $ 96,278
Selling, general and administrative expenses $ 9,142 $ 7,864 $ 18,193 $ 15,902
Depreciation, depletion, amortization, and accretion $ 63,175 $ 51,508 $ 130,015 $ 95,118
Impairment of oil and natural gas properties $ 733,365 $ — $ 865,975 $ —
Net income (loss) attributable to Common and Class B unitholders $ (800,335) $ (9,333) $ (925,855) $ 3,825
Adjusted Net Income (Loss) Attributable to Common and Class B Unitholders (1) $ (6,597) $ 21,965 $ 11,389 $ 46,568
Adjusted Net Income (Loss) Attributable to Common and Class B Unitholders, per unit (1) $ (0.07) $ 0.27 $ 0.13 $ 0.59
Adjusted EBITDA(1) $ 90,579 $ 97,690 $ 175,918 $ 187,552
Interest expense, including settlements paid on interest rate derivative contracts $ 21,364 $ 17,564 $ 42,543 $ 34,813
Estimated maintenance capital expenditures $ 27,031 $ 31,337 $ 52,100 $ 60,151
Distributions to Preferred unitholders $ 6,690 $ 4,596 $ 13,380 $ 6,558
Distributable Cash Flow Available to Common and Class B Unitholders (1) $ 35,494 $ 46,143 $ 67,895 $ 87,980
Distributable Cash Flow per common and Class B unit (1) $ 0.41 $ 0.57 $ 0.79 $ 1.09
Common and Class B unit distribution coverage (1) 1.16x 0.90x 1.13x 0.87x
Weighted average common and Class B units outstanding at record date attributable to distribution period 86,545 81,344 85,505 80,608

(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.

Second Quarter 2015 Highlights:

  • Adjusted EBITDA (a non-GAAP financial measure defined below) decreased 7% to $90.6 million in the second quarter of 2015 from $97.7 million in the second quarter of 2014 and increased 6% from the $85.3 million recorded in the first quarter of 2015.
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) decreased to $35.5 million from the $46.1 million generated in the second quarter of 2014 and increased 10% from the $32.4 million generated in the first quarter of 2015.
  • Adjusted Net Loss Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $6.6 million in the second quarter of 2015, or $0.07 per basic unit, as compared to Adjusted Net Income of $22.0 million, or $0.27 per basic unit, in the second quarter of 2014 and $18.0 million, or $0.21 per basic unit, in the first quarter of 2015. The second quarter of 2015 includes net non-cash expenses of $793.7 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The second quarter 2015 adjustments include a $733.4 million impairment charge on our oil and gas properties. The second quarter of 2014 results included net non-cash losses of $31.3 million.

Three Months Ended Percentage Three Months Percentage
June 30, Increase / Ended March 31, Increase /
2015 2014 (a) (Decrease) 2015 (Decrease)
Total production volumes:
Oil (MBbls) 866 806 7% 850 2%
Natural Gas (MMcf) 23,543 19,649 20% 26,860 (12)%
NGLs (MBbls) 796 696 14% 588 35%
Combined (MMcfe) 33,514 28,664 17% 35,489 (7)%
Average daily production volumes:
Oil (Bbls/day) 9,511 8,860 7% 9,442 2%
Natural Gas (MMcf/day) 259 216 20% 298 (12)%
NGLs (Bbls/day) 8,751 7,652 14% 6,537 35%
Combined (MMcfe/day) 368 315 17% 394 (7)%
Average realized prices, excluding hedges:
Oil (Price/Bbl) $ 50.85 $ 91.74 (45)% $ 42.12 21%
Natural Gas (Price/Mcf) $ 1.69 $ 3.55 (52)% $ 2.08 (19)%
NGLs (Price/Bbl) $ 14.98 $ 25.49 (41)% $ 12.49 20%
Average realized prices, including hedges (b):
Oil (Price/Bbl) $ 58.02 $ 84.40 (31)% $ 54.71 6%
Natural Gas (Price/Mcf) $ 3.16 $ 3.48 (9)% $ 3.05 4%
NGLs (Price/Bbl) $ 16.93 $ 25.37 (33)% $ 14.76 15%
Average NYMEX prices:
Oil (Price/Bbl) $ 57.94 $ 103.01 (44)% $ 48.59 19%
Natural Gas (Price/Mcf) $ 2.63 $ 4.67 (44)% $ 2.98 (12)%

(a) During 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 Six Month Highlights:

  • Adjusted EBITDA (a non-GAAP financial measure defined below) decreased 6% to $175.9 million in the first six months of 2015 from $187.6 million in the first six months of 2014.
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) for the first six months of 2015 decreased 23% to $67.9 million from the $88.0 million generated in the first six 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 $11.4 million for the first six months of 2015, or $0.13 per basic unit, as compared to $46.6 million, or $0.59 per basic unit, in the comparable period of 2014. The first six months of 2015 includes net non-cash expenses of $937.2 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The first six months of 2015 adjustments include an $866.0 million impairment charge on our oil and gas properties. Results for the first six months ended of 2014 included net non-cash expenses of $42.7 million.

Percentage
Six Months Ended June 30, Increase /
2015 2014 (a) (Decrease)
Total production volumes:
Oil (MBbls) 1,715 1,581 8%
Natural Gas (MMcf) 50,403 35,689 41%
NGLs (MBbls) 1,385 1,268 9%
Combined (MMcfe) 69,003 52,786 31%
Average daily production volumes:
Oil (Bbls/day) 9,477 8,737 8%
Natural Gas (MMcf/day) 278 197 41%
NGLs (Bbls/day) 7,650 7,007 9%
Combined (MMcfe/day) 381 292 31%
Average realized prices, excluding hedges:
Oil (Price/Bbl) $ 46.52 $ 89.90 (48)%
Natural Gas (Price/Mcf) $ 1.90 $ 3.74 (49)%
NGLs (Price/Bbl) $ 13.93 $ 30.55 (54)%
Average realized prices, including hedges (b):
Oil (Price/Bbl) $ 56.38 $ 84.36 (33)%
Natural Gas (Price/Mcf) $ 3.10 $ 3.45 (10)%
NGLs (Price/Bbl) $ 16.01 $ 30.10 (47)%
Average NYMEX prices:
Oil (Price/Bbl) $ 53.31 $ 100.89 (47)%
Natural Gas (Price/Mcf) $ 2.82 $ 4.86 (42)%

(a) During 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 $27.0 million in the second quarter of 2015 compared to $36.4 million for the comparable quarter of 2014 and $25.1 million for the first quarter of 2015. Capital spending in the second quarter of 2015 included only maintenance capital expenditures. For the second quarter of 2014, capital spending included maintenance capital expenditures of approximately $31.3 million and growth capital expenditures of $5.1 million primarily associated with the Pinedale acquisition in the Green River Basin. Total capital expenditures were approximately $52.1 million for the first six months of 2015 compared to $67.7 million in the comparable period of 2014.

We currently anticipate a total capital expenditures budget for the remainder of 2015 to range between $57.0 million and $61.0 million, with approximately 67% ($38.2 million to $40.9 million) of the remaining capital expenditures being spent in the third quarter of 2015, excluding any potential future acquisitions. We expect to spend approximately 39% ($22.2 million to $23.8 million) of the remaining 2015 capital budget in the Gulf Coast Basin on the East Haynesville assets drilling both vertical and horizontal wells. Additionally, we expect to spend approximately 37% ($21.1 million to $22.6 million) of the remaining 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. The balance of the remaining 2015 budget ($13.7 million to $14.6 million) is related to maintenance activities in our other operating areas. The potential impact of the LRE Merger and Eagle Rock Merger is not included in the total capital expenditures shown above.

Recent Activities

Acquisitions

LRE Merger

On April 20, 2015, we entered into a Purchase Agreement and Plan of Merger with LRR Energy, L.P. ("LRR Energy" or "LRE") and LRE GP, LLC ("LRE GP"), among others (the "LRE Merger Agreement"), pursuant to which a subsidiary of Vanguard will merge into LRR Energy and, at the same time, Vanguard will acquire LRE GP, the general partner of LRR Energy (the "LRE Merger"). As a result of the transaction, LRR Energy will become a wholly owned subsidiary of Vanguard.

Under the terms of the Merger Agreement, (i) each outstanding common unit representing a limited partner interest in LRE (a "LRE Common Unit") will be converted into the right to receive 0.550 newly issued Vanguard common units or, in the case of fractional Vanguard common units, cash (the "Merger Consideration") and (ii) Vanguard will purchase all of the outstanding limited liability company interests in the LRE GP in exchange for 12,320 newly issued Vanguard common units. Further, in connection with the Merger Agreement, each award of restricted LRE Common Units issued under LRE's long-term incentive plan that is subject to time-based vesting and that is outstanding and unvested immediately prior to the effective time of the Merger will become fully vested and will be deemed to be a LRE Common Unit with the right to receive the Merger Consideration.

The merger is subject to customary closing conditions, including the approval of the LRR Energy unitholders. We expect that the transaction will close in the third quarter of 2015.

Eagle Rock Merger

On May 21, 2015, we entered into a merger agreement (the "Eagle Rock merger agreement") with Eagle Rock Energy Partners, L.P. ("Eagle Rock") and Eagle Rock Energy GP, L.P., the general partner of Eagle Rock ("Eagle Rock GP"), pursuant to which a subsidiary of Vanguard will merge with and into Eagle Rock, with Eagle Rock continuing as the surviving entity and a wholly owned subsidiary of Vanguard (the "Eagle Rock Merger").

Under the terms of the merger agreement, each outstanding common unit representing a limited partner interest in Eagle Rock will be converted into the right to receive 0.185 newly issued Vanguard common units or, in the case of fractional Vanguard common units, cash. The completion of the Eagle Rock Merger is subject to (i) the approval of the merger agreement by the affirmative vote or consent of the holders of at least a majority of the outstanding Eagle Rock common units, voting as a class, (ii) the approval of the issuance of the new Vanguard common units in connection with the merger by the majority of the votes cast affirmatively or negatively by holders of the outstanding Vanguard common units and Vanguard Class B units present in person or by proxy at a duly called unitholder meeting and (iii) other customary closing conditions.

Additionally, Vanguard previously announced that the Annual Meeting of Unitholders to approve the Eagle Rock Merger in addition to other items is scheduled to occur on September 17, 2015. Vanguard's unitholders of record at the close of business on August 6, 2015 will be entitled to receive notice of the Annual Meeting and vote at the Annual Meeting. We expect that the transaction will close in the third quarter of 2015.

Hedging Activities

We have implemented a hedging program for approximately 84% and 50% of our anticipated crude oil production in 2015 and 2016, respectively, with 81% in the form of fixed-price swaps for the balance of 2015. Approximately 88% and 67% 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 22% of anticipated production for the balance of 2015 and 2016, respectively. The impact of the LRE Merger and Eagle Rock Merger discussed above is not included in the amounts or percentages shown below.

July 1 -
December 31, Year Year
2015 2016 2017
Gas Production Hedged:
% Anticipated Production Hedged 88% 67% 40%
Weighted Average Price ($/MMBtu) $ 4.24 $ 4.37 $ 4.18
Oil Production Hedged:
% Anticipated Production Hedged 84% 50% —%
Weighted Average Price ($/Bbl) $ 71.58 $ 81.14 $ —
NGLs Production Hedged:
% Anticipated Production Hedged 9% 22% —%
Weighted Average Price ($/Bbl) $ 46.34 $ 29.96 $ —

For a summary of all commodity and interest rate derivative contracts in place at June 30, 2015, please refer to our Quarterly Report on Form 10-Q which is expected to be filed on or about August 4, 2015.

At June 30, 2015, the fair value of commodity derivative contracts was an asset of approximately $186.7 million, of which $117.3 million settles during the next twelve months. 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 June 3, 2015, the Company entered into the Eighth Amendment to the Credit Agreement which decreased its borrowing base from $2.0 billion to $1.6 billion. However, the Eighth Amendment provides for an automatic increase in the borrowing base of $200.0 million upon closing of the LRE Merger. We expect to negotiate another automatic increase to the borrowing base at closing of the Eagle Rock Merger and we are currently in the process of working through that with our banks. In addition, the Eighth Agreement includes, among other provisions, an amendment of the debt to "Last Twelve Months Adjusted EBITDA" covenant whereby the Company shall not permit such ratio to be greater than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting in 2017 and beyond.

As of July 31, 2015, there was $1.32 billion of outstanding borrowings and $275.5 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 $1.6 billion borrowing base.

At-The-Market ("ATM") Equity Program

Total net proceeds received under our At-The-Market ("ATM") Equity Program were approximately $12.2 million and $20.5 million, after commissions and fees, for the first and second quarter of 2015, respectively. In total for 2015, we have raised net proceeds of $32.7 million, after commissions and fees, from the sales of 2,244,070 common units.

Cash Distributions

On July 16, 2015, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of June 2015 of $0.1175 per common and Class B unit ($1.41 on an annualized basis) expected to be paid on August 14, 2015 to Vanguard unitholders of record on August 3, 2015.

Also on July 16, 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 August 14, 2015 to Vanguard preferred unitholders of record on August 3, 2015.

Conference Call Information

Vanguard will host a conference call on Tuesday, August 4, 2015, to discuss its second quarter 2015 financial results, at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial 1-887-876-9177 or 785-424-1666, for international callers, using access code 5901319 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 September 3, 2015 and may be accessed by calling 1-888-203-1112 or 719-457-0820, for international callers, and using access code 5901319. 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;
  • Gain on acquisition of oil and natural gas properties;
  • Texas margin taxes; and
  • Compensation related items, which include unit-based compensation expense and unrealized fair value of phantom units granted to officers.

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;
  • Gain on acquisition of oil and natural gas properties;
  • Texas margin taxes; and
  • Compensation related items, which include unit-based compensation expense and unrealized fair value on phantom units granted to officers;

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 Six Months Ended
June 30, June 30,
2015 2014 2015 2014
Net income (loss) $ (793,645) $ (4,737) $ (912,475) $ 10,383
Plus:
Interest expense 20,374 16,549 40,563 32,808
Depreciation, depletion, amortization, and accretion 63,175 51,508 130,015 95,118
Impairment of oil and natural gas properties 733,365 865,975
Net (gains) losses on commodity derivative contracts 20,800 38,398 (38,233) 94,436
Cash settlements on matured commodity derivative contracts(b)(c)(d) 42,329 (7,410) 80,620 (19,380)
Net losses on interest rate derivative contracts(e) 281 1,121 1,484 1,579
Gain on acquisition of oil and natural gas properties (32,114)
Texas margin taxes 34 130 142 (281)
Compensation related items 3,866 2,131 7,827 5,003
Adjusted EBITDA $ 90,579 $ 97,690 $ 175,918 $ 187,552
Less:
Interest expense, including settlements paid on interest rate derivatives (21,364) (17,564) (42,543) (34,813)
Estimated maintenance capital expenditures (f) (27,031) (31,337) (52,100) (60,151)
Distributions to Preferred unitholders (6,690) (4,596) (13,380) (6,558)
Proceeds from sale of leasehold interests 1,950 1,950
Distributable Cash Flow Available to Common and Class B Unitholders $ 35,494 $ 46,143 $ 67,895 $ 87,980
Distributions to Common and Class B unitholders 30,507 51,247 60,281 101,365
Excess (shortfall) of distributable cash flow after distributions to unitholders $ 4,987 $ (5,104) $ 7,614 $ (13,385)
Distributable Cash Flow per Common and Class B unit $ 0.41 $ 0.57 $ 0.79 $ 1.09
Common and Class B unit Distribution Coverage 1.16x 0.90x 1.13x 0.87x
(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. $ 2,047 $ — $ 2,567 $ —
(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. $ 11,732 $ 5,983 $ 20,281 $ 10,864
(d) Excludes fair value of restructured derivative contracts. $ — $ — $ (31,945) $ —
(e) Includes settlements paid on interest rate derivatives. $ 990 $ 1,015 $ 1,980 $ 2,005
(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.

CONTACT: Vanguard Natural Resources, LLC Investor Relations Lisa Godfrey, 832-327-2234 investorrelations@vnrllc.com

Source:Vanguard Natural Resources, LLC