News Column

Vanguard Natural Resources, LLC Reports First Quarter 2014 Results

April 29, 2014

HOUSTON--(BUSINESS WIRE)-- Vanguard Natural Resources, LLC (NASDAQ: VNR) (“Vanguard” or “the Company”) today reported financial and operational results for the quarter ended March 31, 2014.

Mr. Scott W. Smith, President and CEO, commented, “Our quarter was highlighted by our $581 million acquisition in the Pinedale field in Wyoming. With this purchase we now have a position in one of the country's most prolific gas properties with many years of development activity ahead. This transaction is a great platform to initiate our growth capital strategy which will enhance our ability to compete for quality assets in the future.”

   
Three Months Ended
March 31,
20142013

($ in thousands, except per unit data)

(Unaudited)

Production (MMcfe/d) 268 199
Oil, natural gas and natural gas liquids sales $ 152,740 $ 96,682
Net losses on commodity derivative contracts $ (56,037 ) $ (29,276 )
Operating expenses $ 45,455 $ 33,515
Selling, general and administrative expenses $ 8,038 $ 6,549
Depreciation, depletion, amortization, and accretion $ 43,610 $ 38,693
Net income (loss) attributable to common and Class B unitholders $ 13,159 $ (27,023 )
Adjusted Net Income Attributable to Common and Class B Unitholders(1) $ 24,604 $ 16,889
Adjusted Net Income Attributable to Common and Class B Unitholders, per unit (1) $ 0.31 $ 0.26
Adjusted EBITDA(1) $ 89,863 $ 72,433
Interest expense, including settlements paid on interest rate derivative contracts $ 17,249 $ 16,385
Maintenance capital expenditures $ 28,814 $ 14,648
Distributions to Preferred unitholders $ 1,962 $

-

Distributable Cash Flow Available to Common and Class B Unitholders(1) $ 41,838 $ 41,400
Distributable Cash Flow per common and Class B unit (1) $ 0.52 $ 0.61
Common and Class B units distribution coverage (1)

0.83

x

1.00

x

Weighted average common and Class B units outstanding 79,606 64,789
 

(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.

 


First Quarter 2014 Highlights:

  • Adjusted EBITDA (a non-GAAP financial measure defined below) increased 24% to $89.9 million in the first three months of 2014 from $72.4 million in the first three months of 2013 and increased 21% from $74.3 million recorded in the fourth quarter of 2013.
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) for the first quarter of 2014 increased 1% to $41.8 million from the $41.4 million generated in the first quarter of 2013 and decreased 2% from $42.7 million generated in the fourth quarter of 2013.
  • We reported net income attributable to common and Class B unitholders for the first quarter of 2014 of $13.2 million or $0.17 per basic unit compared to a reported net loss of $27.0 million or $(0.42) per basic unit in the first quarter of 2013.
  • Adjusted Net Income Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined below) was $24.6 million for the first three months of 2014, or $0.31 per basic unit, as compared to $16.9 million, or $0.26 per basic unit, in the comparable period of 2013. The 2014 results include net non-cash charges of $11.4 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. Results for the first quarter of 2013 included net non-cash charges of $43.3 million.
  • Reported average production of 268 MMcfe per day in the first three months of 2014, up 35% over 199 MMcfe per day produced in the first three months of 2013. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 19%, 67%, and 14% of our production for the first three months of 2014, respectively.

    During the first quarter of 2014, we produced 16,040 MMcf of natural gas, an increase of 34% from the 11,990 MMcf of natural gas produced in the first quarter of 2013, 775 MBbls of oil, an increase of 7% from the 725 MBbls of oil produced in the first quarter of 2013, and 572 MBbls of NGLs, an increase of 123% from the 257 MBbls of NGLs produced in the first quarter of 2013.

    Including the impact of our natural gas hedges in the first three months of 2014, we realized an average price of $3.42 per Mcf on natural gas sales, compared to the unhedged realized average price of $3.96 per Mcf. Our hedged realized average price for oil was $84.32 per barrel, compared to the unhedged realized average price of $87.99 per barrel. The impact of our NGL hedges resulted in an average realized price of $35.87 per barrel of NGLs sales, compared to the unhedged realized average price of $36.72 per barrel.

    Capital Expenditures

    Total capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $31.2 million in the first quarter of 2014 compared to $14.6 million for the comparable quarter of 2013 and $14.5 million for the fourth quarter of 2013. Maintenance capital expenditures in the first quarter of 2014 totaled $28.8 million. The balance of $2.4 million was attributable to growth capital expenditures associated with the Pinedale Acquisition in the Green River Basin.

    During 2014, we intend to concentrate our drilling on low-risk development opportunities with the majority of drilling capital focused on high Btu gas wells and oil wells. We currently anticipate a capital budget for the remainder of 2014 to range between $105.0 million and $110.0 million, excluding any potential future acquisitions. We expect to spend 71% of the remaining 2014 capital budget on the newly acquired assets in the Pinedale Acquisition in the Green River Basin, participating as a non-operated partner in the drilling and completion of vertical natural gas wells. Additionally, we expect to spend 8% of the remaining 2014 capital budget in the Permian Basin, 2% in the Big Horn Basin and the balance in our other operating areas.

    Recent Activities

    On March 31, 2014, we entered into an asset exchange agreement with Marathon Oil Company whereby we will acquire natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry Field properties in Wyoming. The total consideration for this agreement is the mutual exchange and assignment of interests in the properties and cash consideration of $12.0 million we will pay to the seller. The effective date of this exchange is January 1, 2014 and we anticipate closing this acquisition on or before May 1, 2014. We intend to fund this acquisition with borrowings under our existing reserve-based credit facility.

    Hedging Activities

    We enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil and natural gas price volatility on our cash flow from operations. We have mitigated some of the volatility on our cash flow price with derivative contracts through 2017 for oil and natural gas production and through 2015 for NGLs production. Specifically, we have implemented a hedging program for approximately 80% of our anticipated production of crude oil through 2015, approximately 80% of our natural gas production through 2017 and approximately 7% of our NGLs production through 2015. At March 31, 2014, the fair value of commodity derivative contracts was an asset of approximately $29.4 million, of which $17.6 million of net current liability settles during the next twelve months. Currently, we use fixed-price swaps, basis swap contracts, collars, three-way collars, swaptions, call options sold, put spread options, put options sold and range bonus accumulators to hedge oil, natural gas and NGLs prices.

    New commodity derivative contracts put in place during the three months ended March 31, 2014 are as follows:

                   

    Year

    2014

     

    Year

    2015

      Year

    2016
    Year

    2017
    Gas Positions:
    Fixed-Price Swaps
    Notional Volume (MMBtu)

     

    20,875,000

     

    16,425,000

     

    3,660,000

     

    3,650,000

    Fixed Price ($/MMBtu) $ 4.25 $ 4.18 $ 4.13 $ 4.15
    Basis Swaps
    Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
    Notional Volume (MMBtu)

     

    15,030,000

     

    16,425,000

     

    3,660,000

     

    -

    Fixed Price ($/MMBtu) $ (0.20 ) $ (0.27 ) $ (0.35 ) $

    -

    Puts Sold
    Notional Volume (MMBtu)

     

    3,340,000

     

    7,300,000

     

    -

     

    -

    Fixed Price ($/MMBtu) $ 3.50 $ 3.50 $

    -

    $

    -

     
    Oil Positions:
    Three-Way Collars
    Notional Volume (Bbls)

     

    -

     

    181,000

     

    -

     

    -

    Floor Price ($/Bbl) $

    -

    $ 90.00 $

    -

    $

    -

    Ceiling Price ($/Bbl) $

    -

    $ 94.50 $

    -

    $

    -

    Put Sold ($/Bbl) $

    -

    $ 75.00 $

    -

    $

    -

     


    For a summary of all commodity and interest rate derivative contracts in place at March 31, 2014, please refer to our Quarterly Report on Form 10-Q which is expected to be filed on or about May 1, 2014.

    Liquidity Update

    At March 31, 2014, we had indebtedness under our reserve-based credit facility totaling $761.0 million with a borrowing base of $1.3 billion, which provided for $536.2 million in undrawn capacity, after consideration of a $2.8 million reduction in availability for letters of credit.

    As of April 29, 2014, there were $761.0 million of outstanding borrowings and $536.2 million of borrowing capacity under the reserve-based credit facility, after consideration of a $2.8 million reduction in availability for letters of credit and a $1.3 billion borrowing base. We also have approximately $10.0 million in available cash. On April 30, 2014, our borrowing base is expected to increase from $1.3 billion to $1.525 billion pursuant to our semi-annual borrowing base redetermination.

    Cash Distributions

    On April 17, 2014, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of March 2013 of $0.21 per common and Class B unit ($2.52 on an annualized basis) expected to be paid on May 15, 2014 to Vanguard unitholders of record on May 1, 2014.

    Also on April 17, 2014, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per Series A Preferred Unit and $0.33889 per Series B Preferred Unit to be paid on May 15, 2014 to Vanguard preferred unitholders of record on May 1, 2014. This marks the initial distribution payment of our Series B Preferred Units for the period March 11, 2014 through May 15, 2014. Future monthly cash distributions for our Series B Preferred Units will be $0.15885 per unit.

    Conference Call Information

    Vanguard will host a conference call on Wednesday (April 30, 2014) to discuss its first quarter 2014 financial results, at 10:30 a.m. Eastern Time (9:30 a.m. Central). To access the call, please dial (877) 941-6009 or (480) 629-9819 for international callers and ask for the “Vanguard Natural Resources Earnings Call.” The conference call will also be broadcast live via the Internet and can be accessed through the Investor Relations section of Vanguard's corporate website, http://www.vnrllc.com.

    A telephonic replay of the conference call will be available until May 30, 2014 and may be accessed by calling (303) 590-3030 and using the pass code 4679258#. 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 Permian Basin in West Texas and New Mexico, the Green River Basin in Wyoming, the Big Horn Basin in Wyoming and Montana, the Arkoma Basin in Arkansas and Oklahoma, the Gulf Coast Basin in Texas and Mississippi, the Piceance Basin in Colorado, 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.

       

    VANGUARD NATURAL RESOURCES, LLC

    Operating Statistics

    (Unaudited)

     
    Three Months Ended

    Percentage

    Increase /

    (Decrease)

    March 31,

    2014(a)

     

    2013(a)

    Average realized prices, excluding hedges:
    Oil (Price/Bbl) $ 87.99 $ 80.67 9 %
    Natural Gas (Price/Mcf) $ 3.96 $ 2.30 72 %
    NGLs (Price/Bbl) $ 36.72 $ 41.38 (11 )%
    Average realized prices, including hedges (b):
    Oil (Price/Bbl) $ 84.32 $ 79.29 6 %
    Natural Gas (Price/Mcf) $ 3.42 $ 3.52 (3 )%
    NGLs (Price/Bbl) $ 35.87 $ 41.44 (13 )%
    Average NYMEX prices:
    Oil Price (Price/Bbl) $ 98.69 $ 94.32 5 %
    Natural Gas Price (Price/Mcf) $ 5.10 $ 3.34 53 %
    Total production volumes:
    Oil (MBbls) 775 725 7 %
    Natural Gas (MMcf) 16,040 11,990 34 %
    NGLs (MBbls) 572 257 123 %
    Combined (MMcfe) 24,121 17,886 35 %
    Average daily production volumes:
    Oil (Bbls/day) 8,612 8,060 7 %
    Natural Gas (Mcf/day) 178,218 133,227 34 %
    NGLs (Bbls/day) 6,354 2,858

    123

    %
    Combined (MMcfe/day) 268 199 35 %
     

    (a) During 2014 and 2013, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included with ours 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.

     
       

    VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

    CONSOLIDATED STATEMENTS OF OPERATIONS

    (in thousands, except per unit data)

    (Unaudited)

     
    Three Months Ended
    March 31,
    2014   2013
    Revenues:
    Oil sales $ 68,199 $ 58,516
    Natural gas sales 63,543 27,524
    NGLs sales 20,998 10,642
    Net losses on commodity derivative contracts (56,037 ) (29,276 )
    Total revenues 96,703   67,406  
     
    Costs and expenses:
    Production:
    Lease operating expenses 30,421 24,172
    Production and other taxes 15,034 9,343
    Depreciation, depletion, amortization, and accretion 43,610 38,693
    Selling, general and administrative expenses 8,038   6,549  
    Total costs and expenses 97,103   78,757  
     
    Loss from operations (400 ) (11,351 )
     
    Other income (expense):
    Interest expense (16,259 ) (15,438 )
    Net losses on interest rate derivative contracts (458 ) (286 )
    Gain on acquisition of oil and natural gas properties 32,114

    -

    Other 124   52  
    Total other income (expense) 15,521   (15,672 )
    Net income (loss) $ 15,121 $ (27,023 )
    Distributions to Preferred unitholders (1,962 )

    -

     
    Net income (loss) attributable to Common and

    Class B unitholders
    $ 13,159   $ (27,023 )
     
    Net income (loss) per Common and Class B units
    Basic $ 0.17   $ (0.42 )
    Diluted $ 0.16   $ (0.42 )
     
    Weighted average common units outstanding
    Common units – basic 79,186   64,369  
    Common units – diluted 79,472   64,369  
    Class B units – basic & diluted 420   420  
       

    VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

    CONSOLIDATED BALANCE SHEETS

    (in thousands, except unit data)

     

    March 31,

    2014

    December 31,

    2013

    (Unaudited)
    Assets
    Current assets
    Cash and cash equivalents $ 20,905 $ 11,818
    Trade accounts receivable, net 88,581 70,109
    Derivative assets 8,310 21,314
    Other current assets 3,103   2,916  
    Total current assets 120,899   106,157  
     
    Oil and natural gas properties, at cost 3,155,180 2,523,671
    Accumulated depletion, amortization and impairment (755,145 ) (713,154 )
    Oil and natural gas properties evaluated, net – full cost method 2,400,035   1,810,517  
     
    Other assets
    Goodwill 420,955 420,955
    Derivative assets 48,140 60,474
    Other assets 29,458   91,538  
    Total assets $ 3,019,487   $ 2,489,641  
     
    Liabilities and members’ equity
    Current liabilities
    Accounts payable:
    Trade $ 12,830 $ 9,824
    Affiliates 274 249
    Accrued liabilities:
    Lease operating 13,732 12,882
    Development capital 23,269 10,543
    Interest 22,331 11,989
    Production and other taxes 19,190 16,251
    Derivative liabilities 28,930 10,992
    Oil and natural gas revenue payable 20,814 23,245
    Distribution payable 17,680 16,499
    Other 11,283   12,929  
    Total current liabilities 170,333 125,403
     
    Long-term debt 1,308,944 1,007,879
    Derivative liabilities 4,345 4,085
    Asset retirement obligations, net of current portion 95,704 82,208
    Other long-term liabilities 1,012   1,731  
    Total liabilities 1,580,338   1,221,306  
    Commitments and contingencies
    Members’ equity

    Series A Preferred units, 2,559,769 units issued and outstanding at March 31, 2014 and

    2,535,927 at December 31, 2013

    61,634 61,021

    Series B Preferred units, 7,000,000 units issued and outstanding at March 31, 2014

    169,413

    -

    Common units, 79,746,386 units issued and outstanding at March 31, 2014

    and 78,337,259 at December 31, 2013

    1,206,361 1,205,311
    Class B units, 420,000 issued and outstanding at March 31, 2014

    and December 31, 2013
    1,741   2,003  
    Total members’ equity 1,439,149   1,268,335  
    Total liabilities and members’ equity $ 3,019,487   $ 2,489,641  
     


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

    However, 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:

  • Depreciation, depletion, amortization, and accretion;
  • Impairment of oil and natural gas properties;
  • Net gains or losses on commodity derivative contracts;
  • Cash settlements on matured commodity derivative contracts;
  • Net gains and losses on acquisition of oil and natural gas properties;
  • Texas margin taxes;
  • Compensation related items, which include unit-based compensation expense and unrealized fair value on phantom units granted to officers; and
  • Material transaction costs incurred on acquisitions;

    Less:

  • 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 (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a metric commonly used by investors and the analyst community to assess our financial performance from period to period.

    The amount of cash that we have available for distribution depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our GAAP net income, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may be able to pay distributions during periods when we incur net losses. Our board of directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of our limited liability company agreement. Management considers the timing and size of capital expenditures and long-term views about expected results in determining the amount of distributions. Capital spending and the resulting production and net cash provided by 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
    March 31,
    20142013
    Net income (loss) $ 15,121 $ (27,023 )
    Plus:
    Interest expense 16,259 15,438
    Depreciation, depletion, amortization, and accretion 43,610 38,693
    Net losses on commodity derivative contracts 56,037 29,276
    Cash settlements on matured commodity derivative contracts(b)(c) (11,969 ) 13,749
    Net losses on interest rate derivative contracts(d) 458 286
    Gain on acquisition of oil and natural gas properties (32,114 )

    -

    Texas margin taxes (411 ) (317 )
    Compensation related items 2,872 1,728
    Material transaction costs incurred on acquisitions

    -

      603  
    Adjusted EBITDA $ 89,863 $ 72,433
    Less:
    Interest expense, including settlements paid on interest rate derivatives (17,249 ) (16,385 )
    Maintenance capital expenditures (28,814 ) (14,648 )
    Distributions to Preferred unitholders (1,962 )

    -

     
    Distributable Cash Flow Available to Common and Class B unitholders$41,838$41,400
    Distributions to Common and Class B unitholders 50,118   41,580  
    Shortfall of distributable cash flow after distributions to unitholders$(8,280)$(180)
     
    Distributable Cash Flow per Common and Class B unit $ 0.52 $ 0.61
    Common and Class B unit Distribution Coverage

    0.83

    x

    1.00

    x

     
    (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. $

    -

    $ 54
     
    (c) Excludes the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. We consider the amounts paid to sellers for derivative contracts assumed with business combinations a part of the purchase price of the underlying oil and natural gas properties. $ 4,882 $ 7,924
     
    (d) Includes settlements paid on interest rate derivatives $ 990 $ 947
     


    Adjusted Net Income Attributable to Common and Class B Unitholders

    We present Adjusted Net Income Attributable 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 Attributable to Common and Class B Unitholders is a non-GAAP financial measure that is defined as net income attributable 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;
  • Unrealized fair value on phantom units granted to officers;
  • Fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period;
  • Gains on acquisition of oil and natural gas properties; and
  • Material transaction costs incurred on acquisitions.

    This information is provided 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. Adjusted Net Income 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 (loss), operating income (loss), 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 Income (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
    March 31,
    2014   2013
    Net income (loss) attributable to common and Class B unitholders $ 13,159 $ (27,023 )
    Plus (less):
    Change in fair value of commodity derivative contracts 39,186 35,047
    Change in fair value of interest rate derivative contracts (532 ) (661 )
    Unrealized fair value on phantom units granted to officers 23 999
    Fair value of derivative contracts acquired that apply to

    contracts settled during the period

    4,882 7,924
    Gain on acquisition of oil and natural gas properties (32,114 )

    -

    Material transaction costs incurred on acquisitions

    -

      603  
    Adjusted Net Income Attributable to Common and Class B Unitholders $ 24,604   $ 16,889  
     
    Net income (loss) attributable to common and Class B unitholders, per unit $ 0.17 $ (0.42 )
    Plus (less):
    Change in fair value of commodity derivative contracts 0.49 0.54
    Change in fair value of interest rate derivative contracts (0.01 ) (0.01 )
    Unrealized fair value on phantom units granted to officers

    -

    0.02
    Fair value of derivative contracts acquired that apply to

    contracts settled during the period

    0.06 0.12
    Gain on acquisition of oil and natural gas properties (0.40 )

    -

    Material transaction costs incurred on acquisitions

    -

      0.01  
    Adjusted Net Income Attributable to Common and Class B Unitholders, per unit $ 0.31   $ 0.26  





    Vanguard Natural Resources, LLC

    Investor Relations

    Lisa Godfrey, 832-327-2234

    investorrelations@vnrllc.com

    Source: Vanguard Natural Resources, LLC


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