Vanguard Natural Resources Reports Record Adjusted EBITDA, Production And Proved Reserves For 2013 And 2014 Outlook

Vanguard Natural Resources, LLC (NASDAQ: VNR) ("Vanguard" or "the Company") today reported financial and operational results for the full year and fourth quarter ended December 31, 2013.

Mr. Scott W. Smith, President and CEO, commented, "This year the Company continued to execute on our conservative strategy to acquire quality assets which serve as the foundation of our Master Limited Partnership model. With the recent closing of our previously announced Pinedale acquisition, we have established a position in a world class natural gas property with a substantial inventory of high return drilling projects that will deliver long-term benefits to our unitholders. We are looking forward to building upon this successful acquisition in 2014 as the market for high quality assets looks bright for the balance of the year."

Selected Financial Information

A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.
             
Three Months Ended
December 31, Year Ended December 31,
2013       2012 2013       2012
($ in thousands, except per unit data)
Production (BOE/d)

 

36,903

 

22,803

 

35,448

 

18,298
Oil, natural gas and natural gas liquids sales $ 108,319 $ 82,327 $ 443,248 $ 310,356
Net gains (losses) on commodity derivative contracts $ (350 ) $ 28,359 $ 11,256 $ 36,846
Operating expenses $ 39,507 $ 27,817 $ 145,932 $ 103,735
Selling, general and administrative expenses $ 6,763 $ 7,168 $ 25,942 $ 22,466
Depreciation, depletion, amortization, and accretion $ 44,181 $ 30,645 $ 167,535 $ 104,542
Impairment of oil and natural gas properties $

-
$ 229,693 $

-
$ 247,722
Net income (loss) available to Common and Class B
Unitholders $ 870 $ (201,511 ) $ 56,877 $ (168,815 )
Adjusted Net Income Available to Common and Class B

Unitholders (1)
$ 10,922 $ 15,978 $ 69,513 $ 64,131
Adjusted Net Income Available to Common and Class B

Unitholders, per unit (1)
$ 0.14 $ 0.27 $ 0.95 $ 1.18

Adjusted EBITDA (1)
$ 74,344 $ 66,547 $ 309,745 $ 230,512
Interest expense, including settlements paid on interest
rate derivatives $ 15,907 $ 15,248 $ 65,036 $ 44,406
Drilling, capital workover and recompletion expenditures $ 14,469 $ 10,120 $ 56,661 $ 50,405
Distributions to Preferred unitholders $ 1,242 $

-
$ 2,634 $

-
Distributable Cash Flow Available to Common and Class B

Unitholders (1)
$ 42,726 $ 41,179 $ 185,414 $ 141,223

Distributable Cash Flow per Common and Class B unit (1)
$ 0.55 $ 0.70 $ 2.48 $ 2.60

Common and Class B units distribution coverage (1)

 

0.88x

 

1.15x

 

1.00x

 

1.08x
Weighted average Common and Class B units outstanding

 

78,147

 

59,088

 

73,064

 

54,197
 

(1) Non-GAAP financial measures. Please see Adjusted Net Income Available 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.

2014 Outlook

Summary of Estimates

The following table sets forth certain estimates being used by Vanguard to model its anticipated results of operations for the fiscal year ending December 31, 2014 and includes the impact from the recently closed acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming. These estimates do not include any additional acquisitions of oil or natural gas properties. In addition, the expectations below assume Vanguard's current capital structure and does not contemplate any future equity or high yield bond offerings. Actual results for the year ended December 31, 2013 have been provided for comparative purposes.
           
FY 2014E FY 2013
Net Production:          
Oil (Bbls/d) 8,800 - 9,400 8,462
Natural gas (Mcf/d) 215,000 - 229,000 137,632
Natural gas liquids (Bbls/d) 7,200 - 7,650 4,047
Total (BOE/d) 51,883 - 55,217 35,448
 
Costs per BOE:
Lease operating expenses $6.00 - $7.00 $8.15
Production taxes (% of revenue) 10.5% - 11% 9.1%
G&A expenses (excluding non-cash compensation) $1.00 - $1.20 $1.55
Depreciation, depletion and amortization $10.00 - $11.00 $12.95
 
Cash Flow Calculation (in thousands):
Adjusted EBITDA (1) $415,000 309,745
Interest expense, including settlements paid on
interest rate derivatives (72,000) (65,036)
Maintenance capital expenditures (2): (114,000) (56,661)
Distributions to preferred unitholders (5,000) (2,634)
 
Distributable cash flow $224,000 $185,414
 
Excess of net cash after distributions to unitholders $25,500 $618
 
Mid-point distributable cash flow per unit $2.81 $2.48
Mid-point distribution coverage ratio (3) 1.12x 1.00x
Mid-point adjusted net income per unit (1) $1.15 $0.95
Units outstanding (millions) (4) 79.7 74.9
 
Q2 - Q4

Assumed NYMEX Pricing (February 21, 2014) (5) :
Q1 2014 2014 FY 2013
Oil ($/Bbl) $98.81 $97.26 $98.04
Natural gas ($/MMBtu) $5.37 $4.78 $3.66
 
Average NYMEX Differentials:
Oil ($/Bbl) $(11.25) $(9.75) $(10.98)
Natural gas ($/MMBtu) $(1.05) $(1.20) $(1.18)

NGL realization as a percentage of crude oil NYMEX price (6)
35% 30% 34%
 
Capital Expenditures Details (in thousands): Q1 2014 Q2 2014 Q3 2014 Q4 2014
Maintenance Capital:
Operated $ (9,000 ) $ (7,750 ) $ (11,500 ) $ (7,000 )
Non-Operated $ (19,750 ) $ (21,500 ) $ (19,000 ) $ (18,500 )
Growth Capital:
Operated

$

-

$

-

$

-

$

-
Non-Operated $ (4,000 ) $ (6,000 ) $ (6,000 ) $ (6,500 )
Total Capital:
Operated $ (9,000 ) $ (7,750 ) $ (11,500 ) $ (7,000 )
Non-Operated $ (23,750 ) $ (27,500 ) $ (25,000 ) $ (25,000 )
 

(1) Adjusted EBITDA and Adjusted Net Income Available to Common and Class B Unitholders (non-GAAP financial measures defined below) exclude the fair value of derivative contracts acquired that apply to contracts settled during the period (approximately $21.0 MM for the FY 2014E). Adjusted EBITDA and Adjusted Net Income Available to Common and Class B Unitholders assume the mid-point of all the above ranges.

(2) Additional detail regarding the maintenance capital breakout by quarter is listed below. Estimated 2014E maintenance capital expenditures are based on the amount of capital needed to offset the decrease in cash flow from the prior year due to the change in natural gas, oil and NGLs prices and the decline in proved developed producing (PDP) production.

(3) Assumes monthly distribution rate of $0.2075 per unit for January 2014 and $0.21 per unit beginning in February 2014 ($2.5175 per unit on an annualized basis for 2014).

(4) Includes common and Class B units.

(5) NYMEX pricing includes actual settlements for January 2014 and February 2014 for natural gas and January 2014 for oil.

(6) Assumes a weighted average product breakout of 38% ethane, 27% propane, 9% isobutane, 13% n-butane and 13% pentane.

Full Year 2013 Highlights:
  • The annualized monthly distribution of $2.49 per unit as of December 2013 represents a 2.5% increase over the annualized quarterly distribution of $2.43 per unit as of December 2012.
  • Adjusted EBITDA (a non-GAAP financial measure defined below) increased 34% to $309.7 million from the $230.5 million generated in 2012.
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) increased 31% to $185.4 million from the $141.2 million generated in 2012.
  • We reported net income available to Common and Class B unitholders for the year ended December 31, 2013 of $56.9 million or $0.78 per basic unit compared to a net loss of $168.8 million or $(3.11) per basic unit in the year ended December 31, 2012.
  • Adjusted Net Income Available to Common and Class B Unitholders was $69.5 million in 2013, or $0.95 per unit, compared to $64.1 million, or $1.18 per unit, in 2012. The 2013 results include net non-cash losses of $11.8 million that are adjustments to arrive at Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined below). The 2012 results include non-cash expenses of $232.9 million, the largest item of which is a $247.7 million impairment charge on our oil and gas properties.
  • Reported average production of 35,448 BOE per day in 2013 was up 94% over 18,298 BOE per day produced in 2012. On a BOE basis, crude oil, natural gas and natural gas liquids (“NGLs”) accounted for 24%, 65% and 11% of our production, respectively.

During 2013, we produced 50,236 MMcf of natural gas, an increase of 156% from the 19,652 MMcf of natural gas produced in 2012, 3,089 MBbls of oil, an increase of 12% from the 2,758 MBbls of oil produced in 2012, and 1,477 MBbls of NGLs, an increase of 122% from the 664 MBbls of NGLs produced in 2012.

Including the impact of our hedges this year, we realized a net price of $3.39 per Mcf on natural gas sales, $82.26 per Bbl on crude oil sales, and $33.76 per barrel on NGL sales. Our hedged realized average prices exclude premiums paid on derivative contracts and fair value of derivative contracts acquired that apply to contracts settled during the period.

Fourth Quarter 2013 Highlights:
  • Adjusted EBITDA (a non-GAAP financial measure defined below) increased 12% to $74.3 million from $66.5 million in the fourth quarter of 2012 and decreased 10% compared to the $82.7 million recorded in the third quarter of 2013.
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) remained relatively flat at $42.7 million compared to the $41.2 million generated in the fourth quarter of 2012 and decreased 19% from the $52.9 million generated in the third quarter of 2013.
  • We reported a net income for the quarter of $0.9 million or $0.01 per basic unit after deducting distributions to Preferred unitholders compared to a reported net loss of $201.5 million or $(3.41) per basic unit in the fourth quarter of 2012.
  • Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) was $10.9 million in the fourth quarter of 2013, or $0.14 per basic unit, as compared to $16.0 million, or $0.27 per basic unit, in the fourth quarter of 2012. The recent quarter includes net non-cash expenses of $10.0 million that are adjustments to arrive at Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined below). The fourth quarter of 2012 results include net non-cash expenses of $217.5 million, the largest item of which is a $229.7 million impairment charge on our oil and gas properties.
  • Reported average production of 36,903 BOE per day in the fourth quarter of 2013 was up 62% over 22,803 BOE per day produced in the fourth quarter of 2012 and a 5% increase over third quarter of 2013. On a BOE basis, crude oil, natural gas and NGLs accounted for 23%, 62%, and 15% of our production, respectively.

During the quarter we produced 12,670 MMcf of natural gas, an increase of 77% from the 7,147 MMcf of natural gas produced in the fourth quarter of 2012, 773 MBbls of oil, an increase of 11% from the 697 MBbls of oil produced in the fourth quarter of 2012, and 511 MBbls of NGLs, an increase of 143% from the 210 MBbls of NGLs produced in the fourth quarter of 2012.

Including the impact of our natural gas hedges in the fourth quarter of 2013, we realized an average price of $3.41 per Mcf on natural gas sales, compared to the unhedged realized average price of $2.39 per Mcf. Our hedged realized average price for oil was $78.69 per barrel, compared to the unhedged realized average price of $82.15 per barrel. The impact of our NGL hedges resulted in an average realized price of $28.25 per barrel of NGLs sales, compared to the unhedged realized average price of $28.45 per barrel. Our hedged realized average prices exclude premiums paid on derivative contracts and fair value of derivative contracts acquired that apply to contracts settled during the period.

Capital Expenditures

Capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $14.5 million in the fourth quarter of 2013 compared to $10.1 million for the comparable quarter of 2012 and $12.8 million for the third quarter of 2013. Total capital expenditures for 2013 amounted to $56.7 million.

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 2014 of approximately $136.5 million, excluding any potential future acquisitions. We expect to spend 60% of the 2014 capital budget on the newly acquired assets in the Pinedale Acquisition in the Green River Basin. We will participate as a non-operated partner in the drilling and completion of vertical natural gas wells. Additionally, we expect to spend 15% of the 2014 capital budget in the Permian Basin, 13% in the Arkoma Basin and the balance in our other operating areas. Of the $136.5 million capital budget for 2014, $114.0 million is designated as maintenance capital which we expect will keep our cash flow flat. The remaining $22.5 million is designated as growth capital and will be spent in the Pinedale Field.

Recent Activities

On December 23, 2013, we entered into a purchase and sale agreement to acquire natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for a purchase price of $581.0 million. We refer to this acquisition as the "Pinedale Acquisition." We completed this acquisition on January 31, 2014 for an adjusted purchase price of $549.1 million. The purchase price was funded with borrowings under our reserve-based credit facility and is subject to customary post-closing adjustments to be determined based on an effective date of October 1, 2013. Based on internal reserve estimates assuming December 2013 NYMEX strip pricing, the interests acquired have estimated total net proved reserves of 847 billion cubic feet of natural gas (765 billion cubic feet of natural gas when assuming SEC pricing), of which, 79% is natural gas and approximately 43% is proved developed.

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 10% of our NGLs production through 2015. At December 31, 2013, the fair value of commodity derivative contracts was an asset of approximately $73.5 million, of which $13.2 million 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 December 31, 2013 are as follows:

                         
Year Year Year Year
2014 2015 2016 2017
Gas Positions:
Fixed-Price Swaps
Notional Volume (MMBtu)

 

8,135,000

 

14,600,000

 

14,640,000

 

14,600,000
Fixed Price ($/MMBtu) $ 4.28 $ 4.15 $ 4.11

$
4.13
Basis Swaps
Northwest Rockies Pipeline - NYMEX
Notional Volume (MMBtu)

 

11,845,000

 

12,775,000

 

-

 

-
Fixed Price ($/MMBtu) $ (0.21 ) $ (0.29 ) $

-
$

-
Range Bonus Accumulators
Notional Volume (MMBtu)

 

1,460,000

 

1,460,000

 

-

 

-
Bonus ($/MMBtu) $ 0.20 $ 0.20 $

-
$

-
Range Ceiling ($/MMBtu) $ 4.75 $ 4.75 $

-
$

-
Range Floor ($/MMBtu) $ 3.25 $ 3.25 $

-
$

-
 
Oil Positions:
Fixed-Price Swaps
Notional Volume (Bbls)

 

146,000

 

73,000

 

73,200

 

73,000
Fixed Price ($/Bbl) $ 96.48 $ 90.55 $ 87.70 $ 86.60
Puts Sold
Notional Volume (Bbls)

 

73,000

 

73,000

 

73,200

 

73,200
Put Sold ($/Bbl) $ 75.00 $ 75.00 $ 75.00 $ 75.00
 

During 2013, we continued to layer in additional crude oil hedges, Midland-Cushing basis differential hedges, and for the first time hedged a portion of our NGLs exposure through 2015.

For a summary of all commodity and interest rate derivative contracts in place at December 31, 2013, please refer to our Annual Report on Form 10-K which is expected to be filed on or about February 28, 2014.

Liquidity Update

At December 31, 2013, Vanguard had indebtedness under its reserve-based credit facility totaling $460.0 million with a borrowing base of $1.3 billion which provided for $838.2 million in undrawn capacity, after consideration of a $1.8 million reduction in availability for letters of credit.

As of February 26, 2014, there were $935.0 million of outstanding borrowings and $362.2 million of borrowing capacity under the reserve-based credit facility, including a $2.8 million reduction in availability for letters of credit. We also have approximately $10.0 million in available cash.

Cash Distributions

On February 26, 2014, our board of directors approved an increase to our monthly cash distribution from $0.2075 to $0.21 per common unit (from $2.49 to $2.52 on an annualized basis) effective with our February 2014 distribution expected to be paid on April 14, 2014 to unitholders of record as of the close of business on April 1, 2014. Also on February 26, 2014, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per preferred unit expected to be paid on April 15, 2014 to Vanguard preferred unitholders of record on April 1, 2014.

Annual Report on Form 10-K and Unitholders' Schedule K-1

Vanguard's financial statements and related footnotes will be available on our 2013 Form 10-K, which is expected to be filed on or about February 28, 2014 and will be available through the Investor Relations/SEC Filings section of the Vanguard's website at  http://www.vnrllc.com.

Also available for download on our website on or about March 5, 2014 will be unitholders' Schedule K-1s for the tax year 2013. For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1-866-536-1972 or via email at VanguardK1Help@deloitte.com.

Conference Call Information

Vanguard will host a conference call on Thursday (February 27, 2014) to discuss its 2013 full year and fourth quarter results and its 2014 outlook at 10:00 a.m. Eastern Time (9:00 a.m. Central). To access the call, please dial (877) 941-9205 or (480) 629-9818 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 March 28, 2014 and may be accessed by calling (303) 590-3030 and using the pass code 4663736#. A webcast archive will be available on the Investor Relations page at www.vnrllc.com shortly after the call and will be accessible for approximately 30 days. For more information, please contact Lisa Godfrey at (832) 327-2234 or email at investorrelations@vnrllc.com.

About Vanguard Natural Resources, LLC

Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition, production and development of oil and natural gas properties. Vanguard's assets consist primarily of producing and non-producing oil and natural gas reserves located in the Green River Basin in Wyoming, the Arkoma Basin in Arkansas and Oklahoma, the Permian Basin in West Texas and New Mexico, the Big Horn Basin in Wyoming and Montana, the Piceance Basin in Colorado, the Gulf Coast Basin in Texas and Mississippi, the Williston Basin in North Dakota and Montana, the Wind River Basin in Wyoming, and the Powder River Basin in Wyoming. More information on Vanguard can be found at www.vnrllc.com.

Forward-Looking Statements

This press release includes "forward-looking statements" within the meaning of the federal securities laws. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include but are not limited to statements about the acquisition announced in this press release. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for oil, natural gas and NGLs, our ability to replace reserves and efficiently develop our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company's reports filed with the Securities and Exchange Commission. Please see "Risk Factors" in the Company's public filings.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to publicly correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

 
VANGUARD NATURAL RESOURCES, LLC
Operating Statistics
(Unaudited)
 
        Three Months Ended       Year Ended

December 31, (a)

December 31, (a)
2013       2012 2013      

2012 (b)
Average realized prices, excluding hedging:
Oil (Price/Bbl) $ 82.15 $ 80.98 $ 87.06 $ 84.53
Natural Gas (Price/Mcf) $ 2.39 $ 2.37 $ 2.48 $ 2.41
NGLs (Price/Bbl) $ 28.45 $ 42.74 $ 33.72 $ 45.11
 
Average realized prices, including hedging (c):
Oil (Price/Bbl) $ 78.69 $ 84.13 $ 82.26 $ 84.00
Natural Gas (Price/Mcf) $ 3.41 $ 4.19 $ 3.39 $ 4.47
NGLs (Price/Bbl) $ 28.25 $ 42.74 $ 33.76 $ 45.11
 
Average NYMEX prices
Oil (Price/Bbl) $ 97.50 $ 88.23 $ 98.04 $ 94.19
Natural Gas (Price/Mcf) $ 3.60 $ 3.40 $ 3.66 $ 2.96
 
Total production volumes:
Oil (MBbls) 773 697 3,089 2,758
Natural Gas (MMcf) 12,670 7,147 50,236 19,652
NGLs (MBbls) 511 210 1,477 664
Combined (MBOE) 3,395 2,098 12,938 6,697
 
Average daily production volumes:
Oil (Bbls/day) 8,398 7,575 8,462 7,536
Natural Gas (Mcf/day) 137,722 77,688 137,632 53,695
NGLs (Bbls/day) 5,551 2,279 4,047 1,813
Combined (BOE/day) 36,903 22,803 35,448 18,298
 

(a) During 2013 and 2012, we acquired certain oil and natural gas properties and related assets as well as additional interests in these properties. The operating results of these properties are included with ours from the closing date of acquisition forward.

(b) On March 30, 2012, we divested oil and natural gas properties in the Appalachian Basin. As such, there are no operating results from these properties included in our operating results from the closing date of the divestiture 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.

Proved Reserves

Total proved oil and natural gas reserves at December 31, 2013 were 172.2 million barrels of oil equivalent, consisting of 74.5 million barrels of crude oil, condensate, and natural gas liquids and 586.5 billion cubic feet of natural gas. Proved reserves were calculated utilizing the 12-month unweighted average first-day-of-the-month prices ("12-month average prices") during 2013, or $96.90 per Bbl of oil and $3.67 per Mcf of natural gas as compared to $94.67 per Bbl of oil and 2.76 per Mcf of natural gas for 2012.

Using the 12-month average prices, the estimated discounted net present value of Vanguard's proved oil and natural gas reserves, using a 10 percent per annum discount rate (“PV-10 Value”) was approximately $1.8 billion, as compared to a PV-10 Value of approximately $1.6 billion at December 31, 2012.

At December 31, 2013, natural gas reserves accounted for 57% of total proved reserves, and 78% of total proved reserves are developed. The following table summarizes the changes in proved reserves:
             
MBOE
Reserves at December 31, 2012 152,244
Purchases of reserves in place 27,576
Extensions, discoveries and other 2,905
Revisions of previous estimates 2,472
Production (12,938 )
Reserves at December 31, 2013 172,259  
 

Vanguard's proved reserve estimates for all of its properties were prepared by its internal reservoir engineers and were audited by DeGolyer and MacNaughton (D&M), an independent third party engineering firm. D&M's audit covered properties representing 83% of Vanguard's total estimated proved reserves at year-end 2013.
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
 
        Three Months Ended       Year Ended
December 31, December 31,
2013       2012 2013       2012
Revenues:
Oil sales $ 63,468 $ 56,027 $ 268,922 $ 233,153
Natural gas sales 30,324 17,339 124,513 47,270
NGLs sales 14,527 8,961 49,813 29,933
Net gains (losses) on commodity derivative contracts (350 ) 28,359   11,256   36,846  
Total revenues 107,969   110,686   454,504   347,202  
 
Costs and expenses:
Production:
Lease operating expenses 29,481 19,612 105,502 74,366
Production and other taxes 10,026 8,205 40,430 29,369
Depreciation, depletion, amortization and accretion 44,181 30,645 167,535 104,542
Impairment of oil and natural gas properties

-
229,693

-
247,722
Selling, general and administrative expenses 6,763   7,168   25,942   22,466  
Total costs and expenses 90,451   295,323   339,409   478,465  
 
Income (loss) from operations 17,518   (184,637 ) 115,095   (131,263 )
 
Other income (expense):
Other income 3 29 69 220
Interest expense (14,915 ) (14,343 ) (61,148 ) (41,891 )
Net gains (losses) on interest rate derivative contracts (494 ) 125 (96 ) (6,992 )
Net gain (loss) on acquisition of oil and natural gas properties

-
  (2,685 ) 5,591   11,111  
Total other expense (15,406 ) (16,874 ) (55,584 ) (37,552 )
 
Net income (loss) 2,112 (201,511 ) 59,511 (168,815 )
Less: Distributions to Preferred unitholders (1,242 )

-
  (2,634 )

-
 
Net income (loss) available to Common and Class B
unitholders $ 870   $ (201,511 ) $ 56,877   $ (168,815 )
 
Net income (loss) per Common and Class B unit
Basic $ 0.01   $ (3.41 ) $ 0.78   $ (3.11 )
Diluted $ 0.01   $ (3.41 ) $ 0.77   $ (3.11 )
 
Weighted average units outstanding:
Common units – basic 77,727   58,668   72,644   53,777  
Common units – diluted 78,000   58,668   72,992   53,777  
Class B units – basic & diluted 420   420   420   420  
 
       

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)
December 31,
2013 2012
Assets (Unaudited)
Current assets
Cash and cash equivalents $ 11,818 $ 11,563
Trade accounts receivable, net 70,109 51,880
Derivative assets 21,314 46,690
Other currents assets   2,916     3,858  
Total current assets   106,157     113,991  
 
Oil and natural gas properties, at cost 2,523,671 2,126,268
Accumulated depletion, amortization and impairment   (713,154 )   (550,032 )
Oil and natural gas properties evaluated, net – full cost method   1,810,517     1,576,236  
Other assets
Goodwill 420,955 420,955
Derivative assets 60,474 53,240
Other assets   91,538     35,712  
Total assets $ 2,489,641   $ 2,200,134  
 
Liabilities and members’ equity
Current liabilities
Accounts payable:
Trade $ 9,824 $ 8,417
Affiliates 249 32
Accrued liabilities:
Lease operating 12,882 7,884
Developmental capital 10,543 4,754
Interest 11,989 11,573
Production and other taxes 16,251 12,852
Derivative liabilities 10,992 5,366
Oil and natural gas revenue payable 23,245 8,226
Distributions payable 16,499 11,919
Other   12,929     8,479  
Total current liabilities 125,403 79,502
Long-term debt 1,007,879 1,247,631
Derivative liabilities 4,085 11,996
Asset retirement obligations 82,208 60,096
Other long-term liabilities   1,731     3,445  
Total liabilities   1,221,306     1,402,670  
Commitments and contingencies
Members’ equity
Preferred units, 2,535,927 units issued and outstanding at December 31, 2013 61,021

-
Members’ capital, 78,337,259 and 58,706,282 common units issued and outstanding at December 31, 2013 and 2012, respectively 1,205,311 794,426
Class B units, 420,000 issued and outstanding at December 31, 2013 and 2012   2,003     3,038  
Total members’ equity   1,268,335     797,464  
Total liabilities and members’ equity $ 2,489,641   $ 2,200,134  
 

Use of Non-GAAP Measures

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) plus the following adjustments:
  • Net interest expense;
  • 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:
  • Drilling, capital workover and recompletion expenditures;
  • Distributions to Preferred unitholders;

Plus:
  • Proceeds from the sale of leasehold interests.

Distributable Cash Flow Available to Common and Class B Unitholders is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our monthly distribution rates. However, Distributable Cash Flow Available to Common and Class B Unitholders should not be viewed as indicative of the amount that we plan to distribute for a given period. Distributable Cash Flow Available to Common and Class B Unitholders is not intended to be a substitute for net income (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

December 31,
Year Ended

December 31,
2013   2012 2013   2012
Net income (loss) $ 2,112 $ (201,511 ) $ 59,511 $ (168,815 )
Plus:
Interest expense 14,915 14,343 61,148 41,891
Depreciation, depletion, amortization and accretion 44,181 30,645 167,535 104,542
Impairment of oil and natural gas properties

-
229,693

-
247,722
Net (gains) losses on commodity derivative contracts 350 (28,359 ) (11,256 ) (36,846 )

Cash settlements on matured commodity derivative contracts (b)(c)
10,043 15,246 30,905 39,102
Net (gains) losses on interest rate derivative contracts (d) 494 (125 ) 96 6,992
Net (gain) loss on acquisitions of oil and natural gas properties

-
2,685 (5,591 ) (11,111 )
Texas margin taxes 741 392 601 239
Compensation related items 1,486 3,538 5,931 6,796
Material transaction costs incurred on acquisitions 22  

-
  865  

-
 
Adjusted EBITDA $ 74,344 $ 66,547 $ 309,745 $ 230,512
Less:
Interest expense, including settlements paid on interest rate derivatives (15,907 ) (15,248 ) (65,036 ) (44,406 )
Drilling, capital workover and recompletion expenditures (14,469 ) (10,120 ) (56,661 ) (50,405 )
Distributions to Preferred unitholders (1,242 )

-
(2,634 )

-
Proceeds from sale of leasehold interests

-
 

-
 

-
  5,522  
Distributable Cash Flow Available to Common and Class B unitholders $ 42,726 $ 41,179 $ 185,414 $ 141,223
Distributions to Common and Class B unitholders 48,697   35,901   184,796   130,584  
Excess (shortfall) of distributable cash flow after distributions to unitholders $ (5,971 ) $ 5,278   $ 618   $ 10,639  
 
Distributable Cash Flow per Common and Class B unit $ 0.55 $ 0.70 $ 2.48 $ 2.60
Common and Class B unit Distribution Coverage

0.88

x

1.15

x

1.00

x
1.08x
 

(a)

Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

(b)

Excludes premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We consider the cost of premiums paid for derivatives as an investment related to our underlying oil and natural gas properties.
$ 55 $ 1,125 $ 220 $ 11,641

(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.
$ 7,328 $ 12,409 $ 30,200 $ 26,505

(d)

Includes settlements paid on interest rate derivatives
$ 992 $ 905 $ 3,888 $ 2,515
 

Adjusted Net Income Available 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) available 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;
  • 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;
  • Net gains and losses 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 unrealized changes in the fair value of our derivative contracts. Adjusted Net Income Available 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) Available to Common and Class B Unitholders to

Adjusted Net Income Available to Common and Class B Unitholders

(in thousands, except per unit data)

(Unaudited)
 
   

Three Months EndedDecember 31,
   

Year Ended December 31,
2013     2012 2013     2012
 
Net Income (Loss) Available to Common and Class B unitholders $ 870 $ (201,511 ) $ 56,877 $ (168,815 )
Plus (less):
Change in fair value of commodity derivative contracts 3,010 (26,647 ) (10,771 ) (35,890 )
Change in fair value of interest rate derivative contracts (498 ) (1,030 ) (3,792 ) 4,477
Unrealized fair value of phantom units granted to officers 190 379 1,725 1,243
Fair value of derivative contracts acquired that apply to contracts settled during the period 7,328 12,409 30,200 26,505
Net (gain) loss on acquisition of oil and natural gas properties

-
2,685 (5,591 ) (11,111 )
Impairment of oil and natural gas properties

-
229,693

-
247,722
Material transaction costs incurred on acquisitions and mergers

22
 

-
  865  

-
 
Adjusted Net Income Available to Common and Class B unitholders $ 10,922   $ 15,978   $ 69,513   $ 64,131  
Net Income (Loss) Available to Common and Class B
unitholders, per unit $ 0.01 $ (3.41 ) $ 0.78 $ (3.11 )
Plus (less):
Change in fair value of commodity derivative contracts 0.04 (0.45 ) (0.15 ) (0.66 )
Change in fair value of interest rate derivative contracts (0.01 ) (0.02 ) (0.05 ) 0.08
Unrealized fair value of phantom units granted to officers

-

-
0.03 0.02
Fair value of derivative contracts acquired that apply to contracts settled during the period 0.10 0.21 0.41 0.49
Net (gain) loss on acquisition of oil and natural gas properties

-
0.05 (0.08 ) (0.21 )
Impairment of oil and natural gas properties

-
3.89

-
4.57
Material transaction costs incurred on acquisitions and mergers

-
 

-
  0.01  

-
 
Adjusted Net Income Available to Common and Class B unitholders, per unit $ 0.14   $ 0.27   $ 0.95   $ 1.18  

Copyright Business Wire 2010

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