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Vanguard Natural Resources, LLC Reports Third Quarter 2016 Results

HOUSTON, Nov. 08, 2016 (GLOBE NEWSWIRE) -- Vanguard Natural Resources, LLC (NASDAQ:VNR) (“Vanguard” or “the Company”) today reported financial and operational results for the quarter ended September 30, 2016.

Mr. Scott W. Smith, President and CEO, commented, “We are pleased with our results this quarter as our operating teams continue to meet or exceed our production and lease operating expense targets. Over the course of the year, we have made significant progress in reducing our debt, lowering lease operating and G&A costs and reducing capital spending. However, we recognize that work remains to address our bank debt and liquidity issues and we continue to explore various financing options with our financial advisors.”

Selected Financial Information

A summary of selected financial information follows:

    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2016   2015   2016   2015
    ($ in thousands, except per unit data)
(Unaudited)
Production (Mcfe/d)   423,787     386,679     447,347     383,067  
Oil, natural gas and natural gas liquids sales   $ 105,186     $ 90,827     $ 280,102     $ 285,562  
Net gains (losses) on commodity derivative contracts   $ 21,099     $ 64,328     $ (15,752 )   $ 102,561  
Operating expenses   $ 51,209     $ 43,251     $ 150,195     $ 132,509  
Selling, general and administrative expenses   $ 11,454     $ 8,046     $ 35,884     $ 26,239  
Depreciation, depletion, amortization, and accretion   $ 32,096     $ 52,428     $ 118,935     $ 182,443  
Impairment of oil and natural gas properties   $     $ 491,487     $ 365,658     $ 1,357,462  
Impairment of goodwill   $ 252,676     $     $ 252,676     $  
Gain on extinguishment of debt           $ 89,714     $  
Net Loss Attributable to Common and Class B Unitholders   $ (252,085 )   $ (468,967 )   $ (671,536 )   $ (1,394,822 )
Net Loss Attributable to Common and Class B Unitholders, per unit   $ (1.92 )   $ (5.39 )   $ (5.12 )   $ (16.25 )
Adjusted Net Income Attributable to Common and Class B Unitholders (1)   $ 33,672     $ 1,606     $ 74,679     $ 12,995  
Adjusted Net Income Attributable to Common and Class B Unitholders, per unit (1)   $ 0.26     $ 0.02     $ 0.56     $ 0.15  
Adjusted EBITDA attributable to Vanguard unitholders (1)   $ 100,397     $ 88,204     $ 299,857     $ 264,122  
Interest expense, including settlements paid on interest rate derivative contracts   $ 25,019     $ 22,118     $ 79,382     $ 64,661  
Capital expenditures   $ 13,648     $ 28,113     $ 49,117     $ 80,213  
Distributions to Preferred Unitholders, paid and in
arrears (2)(3)
  $ 6,690     $ 6,690     $ 20,069     $ 20,070  
Distributable Cash Flow Available to Common and Class B Unitholders (1)   $ 55,040     $ 31,283     $ 151,289     $ 99,178  
Common and Class B unit distribution coverage (1)(2)       1.02x       1.09x
Weighted average common and Class B units outstanding at record date attributable to distribution period  (2)   131,460     87,018     131,460     86,009  

(1) Non-GAAP financial measures. Please see Adjusted Net Income Attributable to Common and Class B Unitholders, 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.

(2) Our board of directors elected to suspend our monthly cash distribution on our common, Class B and preferred units effective with the February 2016 distribution.

(3) Include actual distributions paid of $2.2 million attributable to the nine months ended September 30, 2016 and cumulative Preferred distributions in arrears of $6.7 million and $17.8 million attributable to the three and nine months ended September 30, 2016, respectively. Distributions to Preferred Unitholders for the three and nine months ended September 30, 2015 reflect actual distributions paid attributable to those periods.

Third Quarter 2016 Highlights:

  • Reported average production of 423,787 Mcfe per day in the third quarter of 2016 was up 10% compared to 386,679 Mcfe per day produced in the third quarter of 2015 and a 4% decrease compared to reported average production of 445,314 Mcfe per day for the second quarter of 2016. On a Mcfe basis, crude oil, natural gas, and NGLs accounted for 16%, 70% and 14%, respectively, of our production.  
  • We reported a net loss attributable to Common and Class B Unitholders for the quarter of $252.1 million or $(1.92) per basic unit after deducting distributions to Preferred Unitholders compared to a net loss of $469.0 million or $(5.39) per basic unit in the third quarter of 2015. 
  • Adjusted EBITDA (a non-GAAP financial measure defined below) increased 14% to $100.4 million in the third quarter of 2016 from $88.2 million in the third quarter of 2015 and decreased 6% from the $106.7 million generated in the second quarter of 2016.  
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) increased 76% to $55.0 million from the $31.3 million generated in the third quarter of 2015 and decreased 6% from the $58.7 million generated in the second quarter of 2016.  
  • Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) was $33.7 million in the third quarter of 2016, or $0.26 per basic unit, as compared to Adjusted Net Income of $1.6 million, or $0.02 per basic unit, in the third quarter of 2015 and Adjusted Net Income of $32.5 million, or $0.24 per basic unit, in the second quarter of 2016. The third quarter of 2016 includes net non-cash losses of $285.7 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The third quarter 2016 adjustments include a $252.7 million loss on impairment of goodwill and a $30.1 million loss from the change in fair value of commodity derivative contracts. The third quarter of 2015 results included net non-cash losses of $470.6 million primarily attributable to a $491.5 million impairment charge on our oil and natural gas properties.
    Three Months Ended
September 30,
  Percentage
Increase /
(Decrease)
  Three Months
Ended

June 30,
  Percentage
Increase /
(Decrease)
    2016 (a)   2015 (b)     2016 (a)  
Average realized prices, excluding hedges:                    
Oil (Price/Bbl)   $ 39.94     $ 40.10     %   $ 39.44     1 %
Natural Gas (Price/Mcf)   $ 1.92     $ 1.94     (1 )%   $ 1.17     64 %
NGLs (Price/Bbl)   $ 12.15     $ 8.86     37 %   $ 13.05     (7 )%
                     
Average realized prices, including hedges (c):                    
Oil (Price/Bbl)   $ 60.25     $ 53.66     12 %   $ 55.90     8 %
Natural Gas (Price/Mcf)   $ 3.13     $ 3.17     (1 )%   $ 2.89     8 %
NGLs (Price/Bbl)   $ 13.32     $ 11.23     19 %   $ 14.22     (6 )%
                     
Average NYMEX prices:                    
Oil (Price/Bbl)   $ 44.95     $ 46.39     (3 )%   $ 45.54     (1 )%
Natural Gas (Price/Mcf)   $ 2.82     $ 2.77     2 %   $ 1.95     45 %
                     
Total production volumes:                    
Oil (MBbls)   1,051     839     25 %   1,266     (17 )%
Natural Gas (MMcf)   27,381     26,242     4 %   27,820     (2 )%
NGLs (MBbls)   883     717     23 %   851     4 %
Combined (MMcfe)   38,988     35,574     10 %   40,524     (4 )%
                     
Average daily production volumes:                    
Oil (Bbls/day)   11,428     9,115     25 %   13,913     (17 )%
Natural Gas (Mcf/day)   297,619     285,236     4 %   305,716     (2 )%
NGLs (Bbls/day)   9,599     7,792     23 %   9,353     4 %
Combined (Mcfe/day)   423,787     386,679     10 %   445,314     (4 )%

(a) During 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

(b) During 2015, 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.

(c) 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.

2016 Nine Month Highlights:

  • Reported average production of 447,347 Mcfe per day in the first nine months of 2016 was up 17% compared to 383,067 Mcfe per day produced in the first nine months of 2015.  On a Mcfe basis, crude oil, natural gas and NGLs accounted for 18%, 68% and 14% of our production, respectively.  
  • We reported a net loss attributable to Common and Class B Unitholders for first nine months of 2016 of $671.5 million or $(5.12) per basic unit after deducting distributions to Preferred Unitholders. 
  • Adjusted EBITDA (a non-GAAP financial measure defined below) increased 14% to $299.9 million in the first nine months of 2016 from $264.1 million in the first nine months of 2015. 
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) for the first nine months of 2016 increased 53% to $151.3 million from the $99.2 million generated in the first nine months of 2015. 
  • Adjusted Net Income Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined below) was $74.7 million for the first nine months of 2016, or $0.56 per basic unit, as compared to $13.0 million, or $0.15 per basic unit, in the comparable period of 2015. The first nine months of 2016 includes net non-cash losses of $743.0 million 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 $365.7 million impairment charge on our oil and natural gas properties, a $252.7 million loss on impairment of goodwill and a $201.4 million loss from the change in fair value of commodity derivative contracts. Results for the first nine months of 2015 included net non-cash losses of $1.4 billion primarily attributable to an impairment charge on our oil and natural gas properties recognized during the period.
    Nine Months Ended
September 30,
  Percentage
Increase /
(Decrease)
    2016 (a)   2015 (b)  
Average realized prices, excluding hedges:            
Oil (Price/Bbl)   $ 34.87     $ 44.41     (21 )%
Natural Gas (Price/Mcf)   $ 1.46     $ 1.91     (24 )%
NGLs (Price/Bbl)   $ 10.84     $ 12.20     (11 )%
Average realized prices, including hedges (c):            
Oil (Price/Bbl)   $ 53.69     $ 55.49     (3 )%
Natural Gas (Price/Mcf)   $ 2.95     $ 3.13     (6 )%
NGLs (Price/Bbl)   $ 12.31     $ 14.38     (14 )%
Average NYMEX prices:            
Oil (Price/Bbl)   $ 40.85     $ 51.04     (20 )%
Natural Gas (Price/Mcf)   $ 2.28     $ 2.80     (19 )%
Total production volumes:            
Oil (MBbls)   3,660     2,554     43 %
Natural Gas (MMcf)   83,592     76,645     9 %
NGLs (MBbls)   2,837     2,102     35 %
 Combined (MMcfe)   122,573     104,577     17 %
Average daily production volumes:            
Oil (Bbls/day)   13,356     9,355     43 %
Natural Gas (Mcf/day)   305,081     280,751     9 %
NGLs (Bbls/day)   10,355     7,698     35 %
Combined (Mcfe/day)   447,347     383,067     17 %

(a) During 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

(b) During 2015, 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.

(c) 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.

Recent Activities

Senior Secured Reserve-Based Credit Facility

In May 2016, the Company’s borrowing base was decreased from $1.78 billion to $1.325 billion, resulting in a borrowing base deficiency of approximately $103.5 million. The Company made monthly payments of $17.5 million through September 30, 2016. As of September 30, 2016, there were approximately $1.35 billion of outstanding borrowings and approximately $2.9 million in outstanding letters of credit resulting in a borrowing deficiency of $31.9 million under the Reserve-Based Credit Facility.

On September 30, 2016, the Company entered into a waiver (the “Waiver”) to its Credit Agreement, in which the lenders thereto (the “First Lien Lenders”) agreed, among other things, subject to certain conditions, to waive any event of default resulting from the Company’s election not to make the approximately $15.0 million semi-annual interest payment due on October 1, 2016 on approximately $381.8 million in aggregate principal amount of Senior Notes due 2020 so long as the payment was made within the 30-day grace period. Pursuant to the Waiver, the First Lien Lenders agreed that the Company’s decision to take advantage of the applicable grace period under the indenture governing the Senior Notes due 2020 would not constitute an event of default under the Credit Agreement.

On October 26, 2016, the Company entered into the Limited Waiver and Eleventh Amendment (the “Waiver and Eleventh Amendment”) to the Credit Agreement. Pursuant to the Waiver and Eleventh Amendment, the First Lien Lenders agreed, among other things, subject to certain conditions, to waive any events of default resulting from the Company’s inability to maintain liquidity in excess of $50.0 million, giving pro forma effect to the Company’s payments of (i) the $15.0 million semi-annual interest payment due on October 1, 2016 on approximately $381.8 million in aggregate principal amount of Senior Notes due 2020 and (ii) the approximately $2.1 million semi-annual interest payment due on December 1, 2016 on approximately $51.2 million in aggregate principal amount of Senior Notes due 2019.

In conjunction with the Waiver and Eleventh Amendment, the Company monetized certain of its outstanding commodity price hedge agreements and used the proceeds along with cash on hand first to pre-pay the First Lien Lenders (i) $29.3 million, representing the remaining outstanding borrowing base deficiency resulting from the Company’s borrowing base redetermination in May 2016 and (ii) $37.5 million, which was applied as the first required monthly payment to the Company’s new borrowing base deficiency resulting from the November 2016 borrowing base redetermination. Also, the Company pledged to the First Lien Lenders certain unencumbered midstream assets as collateral as well as agreed to pay 100% of the net cash proceeds from any asset sale, swap or hedge monetization or other disposition to the First Lien Lenders. The borrowing base may be further reduced as a result of such disposition to the extent of the attributed value of such asset to the borrowing base. Furthermore, any incurrence of second lien debt will require the Company to prepay the First Lien Lenders equal to the net cash proceeds received by the Company from any second lien financing.

On November 3, 2016, the Company completed the semi-annual redetermination of its borrowing base, resulting in a reduction from $1.325 billion to $1.1 billion. After consideration of the first $37.5 million deficiency payment already having been made pursuant to entering into the Waiver and Eleventh Amendment on October 26, 2016, the Company intends to repay the remaining borrowing base deficiency of $187.5 million in five equal monthly installments of $37.5 million beginning in January 2017. The Company anticipates that its forecasted excess cash flow will not be sufficient to pay the remaining borrowing base deficiency.  Refinancing or restructuring our debt, selling assets, reducing or delaying our drilling program or seeking to raise additional capital through non-traditional lending or other private sources of capital will be necessary to satisfy this requirement in order to be back in compliance under the Credit Agreement.

The Company made the $15.1 million semi-annual interest payment with respect to its Senior Notes due 2020 on October 26, 2016.

Capital Expenditures

Total capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $13.6 million in the third quarter of 2016 compared to $28.1 million for the comparable quarter of 2015 and $15.2 million for the second quarter of 2016. Total capital expenditures were approximately $49.1 million for the first nine months of 2016 compared to $80.2 million in the comparable period of 2015.

We have significantly reduced our capital expenditures budget for 2016 as compared to 2015. We currently anticipate a total capital expenditures budget of between $15.0 million and $16.0 million for the remainder of 2016 or a range between $64.0 million and $65.0 million for the full year of 2016 of which $3.8 million is related to capital spent on assets sold in the SCOOP/STACK Divestiture. We expect to spend approximately 54% of the remaining 2016 capital expenditures budget participating as a non-operating partner in the drilling and completion of directional natural gas wells in the Pinedale Field. Additionally, we expect to spend 8% of the remaining 2016 capital expenditures budget participating as a non-operating partner in the drilling and completion of one vertical oil well in Hardin County, Texas and one vertical natural gas well in Claiborne Parish, Louisiana. The balance of the remaining 2016 capital expenditures budget is related to recompletion and maintenance activities in our other operating areas.

Hedging Activities

Prior to the impact of the commodity price hedge monetizations that were executed in conjunction with entering into the Waiver and Eleventh Amendment in October 2016, we had implemented a hedging program for approximately 85% and 20% of our anticipated crude oil production for the balance of 2016 and 2017, respectively, with 49% in the form of fixed-price swaps for the balance of 2016. Approximately 82% and 64% of our anticipated natural gas production for the balance of 2016 and 2017, respectively, was hedged with 85% in the form of fixed-price swaps for the balance of 2016. NGLs production was under fixed-price swaps for approximately 27% of anticipated production for the balance of 2016. Our hedge position as of September 30, 2016, excluding and including the impact of the commodity price hedge monetizations is shown below:

    October 1, -
December 31,
2016
  Year
2017
Gas Production Hedged:        
Excluding Monetization        
% Anticipated Production Hedged   82 %   64 %
Weighted Average Price ($/MMBtu)   $ 4.28     $ 3.67  
Including Monetization        
% Anticipated Production Hedged   58 %   50 %
Weighted Average Price ($/MMBtu)   4.13     3.46  
Oil Production Hedged:        
Excluding Monetization        
% Anticipated Production Hedged   85 %   20 %
Weighted Average Price ($/Bbl)   $ 67.91     $ 84.58  
Including Monetization        
% Anticipated Production Hedged   54 %   14 %
Weighted Average Price ($/Bbl)   $ 62.83     $ 83.98  
NGLs Production Hedged:        
Excluding Monetization        
% Anticipated Production Hedged   27 %   %
Weighted Average Price ($/Bbl)   $ 30.31     $  
Including Monetization        
% Anticipated Production Hedged   24 %   %
Weighted Average Price ($/Bbl)   $ 30.99     $  

The calculations underlying the summary disclosure above are based on fixed price swaps, three-way collars, puts and range bonus accumulators and these calculations exclude basis swap contracts, calls sold and swaptions.The weighted average price for oil and natural gas will fluctuate based on the value of existing three-way collars and short puts as the respective prices settle. The above weighted average prices are calculated based on forward strip commodity prices as of November 7, 2016. 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 November 7, 2016, we had indebtedness under our Reserve-Based Credit Facility totaling approximately $1.3 billion with a borrowing base of $1.1 billion, resulting in a borrowing base deficiency of $187.5 million, after consideration of $0.3 million in outstanding letters of credit. The Company currently has a cash balance of approximately $30.0 million. As previously discussed above, the Company intends to repay the remaining borrowing base deficiency of $187.5 million in five equal monthly installments of $37.5 million beginning in January 2017. The Company anticipates that its forecasted excess cash flow will not be sufficient to pay the remaining borrowing base deficiency.  Refinancing or restructuring our debt, selling assets, reducing or delaying our drilling program or seeking to raise additional capital through non-traditional lending or other private sources of capital will be necessary to satisfy this requirement in order to be back in compliance under the Credit Agreement.

Cash Distributions

Our board of directors elected to suspend our monthly cash distribution on our common, Class B and Cumulative Preferred units effective with the February 2016 distribution.

Conference Call Information

Vanguard will host a conference call on Wednesday, November 9, 2016, to discuss its third quarter 2016 financial results, at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial 1-800-768-6563 or 785-830-7991, for international callers, using access code 9101771 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, 2016 and may be accessed by calling 1-888-203-1112 or 719-457-0820, for international callers, and using access code 9101771. 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 Permian Basin in West Texas and New Mexico, the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama, the Anadarko Basin in Oklahoma and North Texas, the Piceance Basin in Colorado, 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) attributable to Vanguard unitholders in accordance with GAAP.  Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) attributable to Vanguard unitholders plus:

  • Net income (loss) attributable to non-controlling interest.

The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:

  • Net interest expense;
     
  • Depreciation, depletion, amortization, and accretion;
     
  • Impairment of oil and natural gas properties;
     
  • Impairment of goodwill;
     
  • Change in fair value of commodity derivative contracts;
     
  • Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period;
     
  • Fair value of derivative contracts acquired that apply to contracts settled during the period;
     
  • Fair value of restructured derivative contracts;
     
  • Net gains or losses on interest rate derivative contracts;
     
  • Gain on extinguishment of debt;
     
  • Net gains or 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;
     
  • Transaction costs incurred on acquisitions, mergers and divestitures; and
     
  • Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard unitholders.

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) attributable to Vanguard unitholders 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) attributable to Vanguard unitholders plus:

  • Net income (loss) attributable to non-controlling interest.

The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:

  • Depreciation, depletion, amortization, and accretion;
  • Impairment of oil and natural gas properties;
  • Impairment of goodwill;
  • Change in fair value of commodity derivative contracts;
  • Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period;
  • Fair value of derivative contracts acquired that apply to contracts settled during the period;
  • Fair value of restructured derivative contracts;
  • Net gains or losses on interest rate derivative contracts;
  • Gain on extinguishment of debt;
  • Net gains or 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;
  • Transaction costs incurred on acquisitions, mergers and divestitures; and
  • Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard unitholders.

Less:

  • Capital expenditures;
  • Distributions to Preferred unitholders, paid and in arrears.

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 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,
    2016   2015   2016   2015
Net loss attributable to Vanguard unitholders   $ (245,395 )   $ (462,277 )   $ (651,467 )   $ (1,374,752 )
Add: Net income attributable to non-controlling interests   27         91      
Net loss   (245,368 )   (462,277 )   (651,376 )   (1,374,752 )
Plus:                
Interest expense   22,976     21,130     72,612     61,693  
Depreciation, depletion, amortization, and accretion   32,096     52,428     118,935     182,443  
Impairment of oil and natural gas properties       491,487     365,658     1,357,462  
Impairment of goodwill   252,676         252,676      
Change in fair value of commodity derivative contracts (b)   30,135     (33,470 )   201,388     18,014  
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period (b)   833     2,057     2,532     4,624  
Fair value of derivative contracts acquired that apply to contracts settled during the period (b)   3,561     12,453     9,936     32,734  
Fair value of restructured derivative contracts (b)               (31,945 )
Net (gains) losses on interest rate derivative contracts (c)   (764 )   807     6,061     2,291  
Gain on extinguishment of debt           (89,714 )    
Net loss on acquisition of oil and natural gas properties   2,117     284     3,782     284  
Texas margin taxes   (571 )   (522 )   (3,205 )   (380 )
Compensation related items   2,746     3,827     7,721     11,654  
Transaction costs incurred on acquisitions, mergers and divestitures   75         3,198      
Adjusted EBITDA before non-controlling interest   100,512     88,204     300,204     264,122  
Adjusted EBITDA attributable to non-controlling interest   (115 )       (347 )    
Adjusted EBITDA attributable to Vanguard unitholders   100,397     88,204     299,857     264,122  
Less:                
Interest expense, including settlements paid on interest rate derivatives   (25,019 )   (22,118 )   (79,382 )   (64,661 )
Capital expenditures   (13,648 )   (28,113 )   (49,117 )   (80,213 )
Distributions to Preferred unitholders, paid and in arrears (d)   (6,690 )   (6,690 )   (20,069 )   (20,070 )
Distributable Cash Flow Available to Common and Class B Unitholders   $ 55,040     $ 31,283     $ 151,289     $ 99,178  
Distributions to Common and Class B unitholders (e)       30,674         90,955  
Excess of distributable cash flow after distributions to unitholders   $ 55,040     $ 609     $ 151,289     $ 8,223  

(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) These items are included in the net gains (losses) on commodity derivative contracts line item in the consolidated statements of operations as follows:

  Three Months Ended   Nine Months Ended
  September 30,   September 30,
  2016   2015   2016   2015
Net cash settlements received on matured commodity derivative contracts $ 55,628     $ 45,368     $ 198,104     $ 125,988  
Change in fair value of commodity derivative contracts (30,135 )   33,470     (201,388 )   (18,014 )
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period (833 )   (2,057 )   (2,532 )   (4,624 )
Fair value of derivative contracts acquired that apply to contracts settled during the period (3,561 )   (12,453 )   (9,936 )   (32,734 )
Fair value of restructured derivative contracts             31,945  
Net gains (losses) on commodity derivative contracts $ 21,099     $ 64,328     $ (15,752 )   $ 102,561  

(c) Net gains (losses) on interest rate derivative contracts as shown on the consolidated statements of operations is comprised of the following:

  Three Months Ended   Nine Months Ended
  September 30,   September 30,
  2016   2015   2016   2015
Cash settlements paid on interest rate derivative contracts $ (2,043 )   $ (988 )   $ (6,770 )   $ (2,968 )
Change in fair value of interest rate derivative contracts 2,807     181     709     677  
Net gains (losses) on interest rate derivative contracts $ 764     $ (807 )   $ (6,061 )   $ (2,291 )

(d) Include actual distributions paid of $2.2 million attributable to the nine months ended September 30, 2016 and cumulative Preferred distributions in arrears of $6.7 million and $17.8 million attributable to the three and nine months ended September 30, 2016, respectively. Distributions to Preferred Unitholders for the three and nine months ended September 30, 2015 reflect actual distributions paid attributable to those periods.

(e) Our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. Our ability to resume distributions is at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.

Adjusted Net Income (Loss) Attributable to Common and Class B Unitholders

We present Adjusted Net Income Available to Common and Class B Unitholders in addition to our reported net income (loss) attributable to common and Class B Unitholders in accordance with GAAP.  Adjusted Net Income Available to Common and Class B Unitholders is a non-GAAP financial measure that is defined as net income available to Common and Class B Unitholders plus the following adjustments:

  • Change in fair value of commodity derivative contracts;
  • Change in fair value of interest rate derivative contracts;
  • Fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. Also excludes the fair value of derivative contracts acquired and settled during the period;
  • Net gains or losses on acquisitions of oil and natural gas properties;
  • Impairment of oil and natural gas properties;
  • Impairment of goodwill;
  • Gain on extinguishment of debt; and
  • Transaction costs incurred on acquisitions, mergers and divestitures.

We present Adjusted Net Income Available to Common and Class B Unitholders because management believes exclusion of the impact of these items will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the significant fluctuations that commodity price volatility has on our results, particularly as it relates to changes in the fair value of our derivative contracts.

In particular, we make the adjustment for the change in fair value of commodity derivative contracts to allow investors to make a comparison of our quarterly results without the non-cash impact of commodity price fluctuations from period to period resulting from changes in the mark-to-market value of our portfolio of commodity derivative contracts. Rather than highlighting the significant fluctuations that commodity price volatility has on Net Income, we are aiming to give investors a meaningful picture of our performance (especially versus prior periods) that shows how the company performed without the impact of the value of our portfolio of commodity derivative contracts. The fluctuations in the value of our portfolio of commodity derivatives contracts is related to futures pricing which is not a good indicator of historical performance of the business during the periods presented. Furthermore, any increases or decreases in the value of our portfolio of commodity derivatives contracts will result in non-cash charges or non-cash income.  The inherent value (or cost) of such contracts is the amount of cash which our counterparties pay to us, or, with respect to costs, the amount which we paid to acquire the contracts and the amount that we are required to pay to our counterparties upon settlement.  We believe this non-GAAP measure allows our investors to measure our actual performance without the impact of certain non-cash items that do not actually reflect the performance of the Company for the periods presented.

We also make the adjustment for the change in fair value of interest rate derivative contracts to give investors a period to period comparison without showing the impact of non-cash gains or losses related to the mark-to-market valuation of these derivatives contracts.

Adjusted Net Income (Loss) Attributable to Common and Class B Unitholders 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.

 
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Loss Attributable to Common and Class B Unitholders to Adjusted Net Income Attributable to Common and Class B Unitholders
(in thousands, except per unit data)
(Unaudited)
 
  Three Months Ended   Nine Months Ended
  September 30,   September 30,
  2016   2015   2016   2015
Net Loss Attributable to Common and Class B Unitholders $ (252,085 )   $ (468,967 )   $ (671,536 )   $ (1,394,822 )
Plus (less):              
Change in fair value of commodity derivative contracts(a)(b) 30,135     (33,470 )   201,388     18,014  
Change in fair value of interest rate derivative contracts(c)(d) (2,807 )   (181 )   (709 )   (677 )
Fair value of derivative contracts acquired that apply to contracts settled during the period 3,561     12,453     9,936     32,734  
Net loss on acquisition of oil and natural gas properties 2,117     284     3,782     284  
Impairment of oil and natural gas properties     491,487     365,658     1,357,462  
Impairment of goodwill 252,676         252,676      
Gain on extinguishment of debt         (89,714 )    
Transaction costs incurred on acquisitions, mergers and divestitures 75         3,198      
Adjusted Net Income Attributable to Common and Class B Unitholders $ 33,672     $ 1,606     $ 74,679     $ 12,995  


Net Loss Attributable to Common and Class B Unitholders, per unit $ (1.92 )   $ (5.39 )   $ (5.12 )   $ (16.25 )
Plus (less):              
Change in fair value of commodity derivative contracts 0.23     (0.38 )   1.53     0.21  
Change in fair value of interest rate derivative contracts (0.02 )       (0.01 )   (0.01 )
Fair value of derivative contracts acquired that apply to contracts settled during the period 0.03     0.14     0.08     0.38  
Net loss on acquisition of oil and natural gas properties 0.02         0.03      
Impairment of oil and natural gas properties     5.65     2.79     15.82  
Impairment of goodwill 1.92         1.92      
Gain on extinguishment of debt         (0.68 )    
Transaction costs incurred on acquisitions, mergers and divestitures         0.02      
Adjusted Net Income Attributable to Common and Class B Unitholders, per unit $ 0.26     $ 0.02     $ 0.56     $ 0.15  
               
Weighted average common and Class B units outstanding 131,460     87,012     131,282     85,834  

(a) Change in fair value of commodity derivative contracts reflects the increase or decrease in the mark-to-market value of the commodity derivative contracts. Any increase in value is reduced from Net Loss Attributable to Common and Class B Unitholders, while any decrease is added back into Net Loss Attributable to Common and Class B Unitholders.

(b) Does not include adjustments for premiums paid on derivatives during the period presented, the fair value of acquired derivatives that settled during the period presented or the fair value of restructured derivatives contracts.

(c) Change in fair value of interest rate derivative contracts reflects the increase or decrease in the mark-to-market value of the interest rate derivative contracts. Any increase in the fair value of interest rate derivative contracts is reduced from Net Loss Attributable to Common and Class B Unitholders, while any decrease in the fair value of interest rate derivative contracts is added back into Net Loss Attributable to Common and Class B Unitholders.

(d) Does not include cash settlements paid on interest rate derivatives.

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

Vanguard Natural Resources, LLC
VNR (Common Stock)
ExchangeNASDAQ GS (US Dollar)
Price$0.08
Change (%) + 0.01 (14.29%)
Volume1,154,731
Data as of 03/15/17 4:00 p.m. ET
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5847 San Felipe, Suite 3000

Houston, Texas 77057

Phone: (832) 327-2255

Fax : (832) 327-2260