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EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, LLCexhibit31-1.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, LLCexhibit31-2.htm
EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, LLCexhibit32-2.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, LLCexhibit32-1.htm
EX-10.3 - EXHIBIT 10.3 - Vanguard Natural Resources, LLCexhibit10-3.htm

 



 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
 
     
(Mark One)
   
x
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2009
OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from          to
 
Commission File Number:  001-33756
 
Vanguard Natural Resources, LLC
(Exact Name of Registrant as Specified in Its Charter)
 
Delaware
 
61-1521161
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)
 
7700 San Felipe, Suite 485
Houston, Texas
 
77063
(Address of Principal Executive Offices)
 
(Zip Code)
 
Telephone Number: (832) 327-2255
 Internet Website: www.vnrllc.com
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x   No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  o   No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o
Accelerated filer x
Non-accelerated filer o
Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o  No  x
  
Common units outstanding on November 4, 2009: 16,078,673. 




 
 

 

4
VANGUARD NATURAL RESOURCES, LLC
TABLE OF CONTENTS


   
Page
 
     
 
 
 
 
 
 
 
 
     
 

 
 

 


 

Below is a list of terms that are common to our industry and used throughout this document:
 
/day
=
per day
 
Mcf
=
thousand cubic feet
Bbls
=
barrels
 
Mcfe
=
thousand cubic feet of natural gas equivalents
Bcfe
=
billion cubic feet of natural gas equivalents
 
MMBtu
=
million British thermal units
Btu
=
British thermal unit
 
MMcf
=
million cubic feet
Gal
=
gallons
 
NGL
=
natural gas liquids
 
When we refer to natural gas, natural gas liquids and oil in “equivalents,” we are doing so to compare quantities of natural gas liquids and oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which 42 gallons is equal to one Bbl of oil and one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
 
References in this report to (1) “us,” “we,” “our,” “the Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC, Trust Energy Company, LLC (“TEC”), VNR Holdings, Inc. (“VNRH”), Ariana Energy, LLC (“Ariana Energy”), Vanguard Permian, LLC (“Vanguard Permian”) and VNR Finance Corp. (“VNRF”) and (2) “Vanguard Predecessor,” “Predecessor,” “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC. 

 
 

 


 
 
 
 
(in thousands, except per unit data)
(Unaudited)

  
 
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
 
2009
   
2008
   
2009
   
2008
 
Revenues:
 
 
   
 
                 
Natural gas, natural gas liquids and oil sales
 
$
11,324
   
$
20,839
   
$
29,930
   
$
55,693
 
Gain (loss) on commodity cash flow hedges
   
(463
)
   
45
     
(1,737
)
   
616
 
Gain (loss) on other commodity derivative contracts
   
(4,210
)
   
63,364
     
7,302
     
(16,453
)
Total revenues
   
6,651
     
84,248
     
35,495
     
39,856
 
                                 
Costs and expenses:
                               
Lease operating expenses
   
3,322
     
3,485
     
9,233
     
7,800
 
Depreciation, depletion, amortization, and accretion
   
3,272
     
4,187
     
9,700
     
10,341
 
Impairment of natural gas and oil properties
   
     
     
63,818
     
 
Selling, general and administrative expenses
   
2,137
     
1,560
     
8,230
     
4,843
 
Production and other taxes
   
974
     
1,263
     
2,537
     
3,658
 
Total costs and expenses
   
9,705
     
10,495
     
93,518
     
26,642
 
                                 
Income (loss) from operations
   
(3,054
)
   
73,753
     
(58,023
)
   
13,214
 
                                 
Other income and (expense):
                               
Interest income
   
     
4
     
     
16
 
Interest expense
   
(1,042
)
   
(1,489
)
   
(3,034
)
   
(3,863
)
Gain on acquisition of natural gas and oil properties
   
5,878
     
     
5,878
     
 
Loss on interest rate derivative contracts
   
(1,081
)
   
(459
)
   
(853
)
   
(510
)
Total other income (expense)
   
3,755
     
(1,944
)
   
1,991
     
(4,357
)
                                 
Net income (loss)
 
$
701
   
$
71,809
   
$
(56,032
)
 
$
8,857
 
                                 
Net income (loss) per unit:
                               
Common & Class B units – basic
 
$
0.05
   
$
5.90
   
$
(4.24
)
 
$
0.77
 
                                 
Common & Class B units – diluted
 
$
0.05
   
$
5.90
   
$
(4.24
)
 
$
0.77
 
                                 
Weighted average units outstanding:
                               
Common units – basic & diluted
   
14,027,186
     
11,749,421
     
12,779,869
     
11,115,463
 
Class B units – basic & diluted
   
420,000
     
420,000
     
420,000
     
420,000
 

See accompanying notes to consolidated financial statements

 
3

 

(in thousands)
   
September 30,
 2009
   
December 31,
2008
 
   
(Unaudited)
       
Assets
           
Current assets
           
Cash and cash equivalents
  $ 2,046     $ 3  
Trade accounts receivable, net
    5,410       6,083  
Derivative assets
    19,516       22,184  
Other receivables
    2,912       2,763  
Other current assets
    766       845  
Total current assets
    30,650       31,878  
                 
                 
    Natural gas and oil properties, at cost
    341,898       284,447  
    Accumulated depletion
    (175,493 )     (102,178 )
Natural gas and oil properties evaluated, net – full cost method
    166,405       182,269  
                 
Other assets
               
    Derivative assets
    6,850       15,749  
    Deferred financing costs
    3,301       882  
    Other assets
    1,627       1,784  
Total assets
  $ 208,833     $ 232,562  
                 
Liabilities and members’ equity
               
                 
Current liabilities
               
    Accounts payable – trade
  $ 611     $ 2,148  
    Accounts payable – natural gas and oil
    1,525       1,327  
    Payables to affiliates
    866       2,555  
    Deferred swap liability
    997        
    Derivative liabilities
    29       486  
    Phantom unit compensation accrual
    3,034        
    Accrued ad valorem taxes
    1,591       34  
    Accrued expenses
    344       1,214  
Total current liabilities
    8,997       7,764  
                 
    Long-term debt
    123,500       135,000  
    Derivative liabilities
    2,801       2,313  
    Deferred swap liability
    2,075        
    Asset retirement obligations
    4,133       2,134  
Total liabilities
    141,506       147,211  
                 
Commitments and contingencies
               
                 
Members’ equity
               
        Members’ capital, 16,078,673 common units issued and outstanding at September  30, 2009 and 12,145,873 at December 31, 2008
    67,409       88,550  
    Class B units, 420,000 issued and outstanding at September 30, 2009 and December 31, 2008
    6,045       4,606  
    Accumulated other comprehensive loss
    (6,127 )     (7,805 )
Total members’ equity
    67,327       85,351  
Total liabilities and members’ equity
  $ 208,833     $ 232,562  

See accompanying notes to consolidated financial statements

 
4

 

 



 
Common
Units
 
Common Units
Amount
 
Class B
Units
 
Class B
Units Amount
 
Accumulated Other Comprehensive Loss
   
Total
Members’ Equity
 
Balance, January 1, 2008
10,795,000
 
$
90,258
 
420,000
 
$
2,132
 
$
(10,059
)
 
$
82,331
 
Distributions to members ($0.291, $0.445, $0.445 and $0.50 per unit to unitholders of record February 7, 2008, April 30, 2008, July 31, 2008 and October 31, 2008, respectively)
   
(19,423
)
   
(706
)
 
     
(20,129
)
Issuance of common units for acquisition of natural gas and oil properties, net of offering costs of $54
 
1,350,873
   
21,306
 
 
   
   
     
21,306
 
Unit-based compensation
   
161
 
 —
   
3,180
   
     
3,341
 
Net loss
   
(3,752
)
 —
   
   
     
(3,752
)
Settlement of cash flow hedges in other comprehensive income
 
   
 
 
   
   
2,254
     
2,254
 
Balance at December 31, 2008
12,145,873
 
$
88,550
 
420,000
 
$
4,606
 
$
(7,805
)
 
$
85,351
 
Distributions to members ($0.50 per unit to unitholders of record January 31, 2009, April 30, 2009 and July 31, 2009, respectively)
   
(18,219
)
   
(630
)
 
     
(18,849
)
Issuance of common units, net of offering costs of $491
3,932,800
   
53,192
 
   
   
     
53,192
 
Unit-based compensation
   
(82
)
   
2,069
   
     
1,987
 
Net loss
   
(56,032
)
   
   
     
(56,032
)
Settlement of cash flow hedges in other comprehensive income
   
 
   
   
1,678
     
1,678
 
Balance at September 30, 2009
16,078,673
 
$
67,409
 
420,000
 
$
6,045
 
$
(6,127
)
 
$
67,327
 

 
See accompanying notes to consolidated financial statements

 
5

 

(Unaudited)
(in thousands)
   
Nine Months Ended
September 30,
 
   
2009
   
2008
 
Operating activities
           
Net income (loss)
  $ (56,032 )   $ 8,857  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depreciation, depletion, amortization, and accretion
    9,700       10,341  
Impairment of natural gas and oil properties
    63,818        
Amortization of deferred financing costs
    363       264  
Unit-based compensation
    2,311       2,708  
Unrealized fair value of phantom units granted to officers
    3,034        
Amortization of premiums paid and non-cash settlements on derivative contracts
    4,383       3,982  
Unrealized losses on other commodity and interest rate derivative contracts
    16,105       6,463  
Gain on acquisition of natural gas and oil properties
    (5,878 )      
Changes in operating assets and liabilities:
               
Trade accounts receivable
    673       (6,730 )
Other receivables
    (149 )      
Payables to affiliates
    (1,689 )     662  
Other current assets
    11       (435 )
Price risk management activities, net
    (13 )     (452 )
Accounts payable
    (1,339 )     673  
Accrued expenses
    687       2,300  
Other assets
    (27 )      
Net cash provided by operating activities
    35,958       28,633  
                 
Investing activities
               
Additions to property and equipment
    (9 )     (70 )
Additions to natural gas and oil properties
    (2,981 )     (13,360 )
Acquisitions of natural gas and oil properties
    (49,964 )     (99,815 )
Deposits and prepayments of natural gas and oil properties
    (699 )     (901 )
Net cash used in investing activities
    (53,653 )     (114,146 )
                 
Financing activities
               
Proceeds from borrowings
    16,800       112,900  
Repayment of debt
    (28,300 )     (15,800 )
Distributions to members
    (18,849 )     (13,846 )
Proceeds from equity offering
    53,192        
Financing costs
    (2,781 )     (274 )
Purchase of units for issuance as unit-based compensation
    (324 )     (236 )
Net cash provided by financing activities
    19,738       82,744  
                 
Net increase (decrease) in cash and cash equivalents
    2,043       (2,769 )
                 
Cash and cash equivalents, beginning of period
    3       3,110  
Cash and cash equivalents, end of period
  $ 2,046     $ 341  
                 
Supplemental cash flow information:
               
Cash paid for interest
  $ 2,964     $ 3,342  
Non-cash financing and investing activities:
               
Asset retirement obligations
  $ 1,913     $ 2,155  
Derivatives assumed in acquisition of natural gas and oil properties
  $ 4,128     $ 2,468  
Deferred swap liability
  $ 3,072     $  
Non-monetary exchange of natural gas and oil properties
  $ 2,660     $  
Issuance of common units for acquisition of natural gas and oil properties
  $     $ 21,360  
Transfer of deposit for natural gas and oil properties
  $     $ 7,830  
See accompanying notes to consolidated financial statements

6

(Unaudited)
(in thousands)

 
 
   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
 
2009
   
2008
   
2009
   
2008
 
                             
Net income (loss)
 
$
701
   
$
71,809
   
$
(56,032
)
 
$
8,857
 
                                 
Net gains (losses) from derivative contracts:
                               
Unrealized mark-to-market gains arising during the period
   
     
     
     
2,747
 
Reclassification adjustments for settlements
   
434
     
7
     
1,678
     
(564
Other comprehensive income
   
434
     
7
     
1,678
     
2,183
 
                                 
Comprehensive income (loss)
 
$
1,135
   
71,816
   
$
(54,354
)
 
11,040
 
 
 
See accompanying notes to consolidated financial statements


 
7

 
 
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)


Vanguard Natural Resources, LLC is a publicly-traded limited liability company focused on the acquisition and development of mature, long-lived natural gas and oil properties in the United States. Through our operating subsidiaries, we own properties in the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee, in the Permian Basin, primarily in west Texas and southeastern New Mexico, and in South Texas.
 
References in this report to (1) “us,” “we,” “our,” “the Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC, Trust Energy Company, LLC (“TEC”), VNR Holdings, Inc. (“VNRH”), Ariana Energy, LLC (“Ariana Energy”), Vanguard Permian, LLC (“Vanguard Permian”) and VNR Finance Corp. (“VNRF”) and (2) “Vanguard Predecessor,” “Predecessor,” “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.
 
We were formed in October 2006 but effective January 5, 2007, Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) was separated into our operating subsidiary and Vinland Energy Eastern, LLC ("Vinland"). As part of the separation, we retained all of our Predecessor’s proved producing wells and associated reserves. We also retained 40% of our Predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres and a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing gas and oil wells. In the separation, Vinland was conveyed the remaining 60% of our Predecessor’s working interest in the known producing horizons in this acreage, 100% of our Predecessor’s working interest in depths above and 100 feet below our known producing horizons, all of our gathering and compression assets, and all employees other than our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer. Vinland operates all of our existing wells in Appalachia and all of the wells that we drill in Appalachia. We refer to these events as the "Restructuring."
 
1.  
Summary of Significant Accounting Policies

The accompanying financial statements are unaudited and were prepared from our records. We derived the consolidated balance sheet as of December 31, 2008, from the audited financial statements filed in our 2008 Annual Report on Form 10-K.  Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles (“GAAP”). You should read this Quarterly Report on Form 10-Q along with our 2008 Annual Report on Form 10-K, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net loss, members’ equity, or net cash flows.

As of September 30, 2009, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2008 Annual Report on Form 10-K, except for those under Recently Adopted Accounting Pronouncements.

(a)  
Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of September 30, 2009 and December 31, 2008 and for the three and nine months ended September 30, 2009 and 2008 include our accounts and those of our wholly-owned subsidiaries.  We present our financial statements in accordance with GAAP.  All intercompany transactions and balances have been eliminated upon consolidation.
  
(b)  
Recently Adopted Accounting Pronouncements:

Effective July 1, 2009, the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) became the single official source of authoritative, nongovernmental GAAP in the United States. The historical GAAP hierarchy was eliminated, and the ASC became the only level of authoritative GAAP, other than guidance issued by the Securities and Exchange Commission (“SEC”). Our accounting policies were not affected by the conversion to ASC. However, references to specific accounting standards in the footnotes to our consolidated financial statements have been changed to refer to the appropriate section of ASC.

In September 2006, the FASB issued guidance which defines fair value, establishes the framework for measuring fair value and expands disclosures about fair value measurements.  This guidance is contained in ASC Topic 820, “Fair Value Measurements and Disclosures (“ASC Topic 820”). In February 2008, the FASB deferred the effective date applicable to us to January 1, 2009 for all nonfinancial assets and liabilities, except for those that are recognized or disclosed at fair value on a recurring basis (that is, at least annually).  On January 1, 2008, we adopted the provisions of ASC Topic 820, as it relates to financial assets and financial liabilities and we determined that the impact of the additional assumptions on fair value measurements did not have a material effect on our financial position or results of operations. We adopted the deferred provisions of ASC Topic 820 on January 1, 2009, as it relates to nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact on our financial position or results of operations. See Note 5. Fair Value Measurements for further discussion.

8

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
In April 2009, the FASB issued additional guidance for estimating fair value in accordance with ASC Topic 820. The additional guidance addresses determining fair value when the volume and level of activity for an asset or liability have significantly decreased and identifying transactions that are not orderly. We adopted the provisions of this guidance on June 30, 2009 and the adoption did not have a material impact on our consolidated financial statements.

In December 2007, the FASB issued guidance which established principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. This guidance is contained in ASC Topic 805, “Business Combinations (“ASC Topic 805”). This guidance also established disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. Effective January 1, 2009, we adopted the provisions of ASC Topic 805 and applied the provisions to our acquisitions completed in the third quarter 2009. See Note 2. Acquisitions for further discussion.

In April 2009, the FASB issued additional guidance which amended the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under ASC Topic 805. The requirements of ASC Topic 805 were carried forward for acquired contingencies, which would require that such contingencies be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the allocation period. Otherwise, companies would typically account for the acquired contingencies in accordance with ASC Topic 450, “Contingencies. The adoption of the provisions in this additional guidance did not affect our consolidated financial statements.

In March 2008, the FASB issued guidance intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. This guidance is contained in ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”). The guidance achieves these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit risk-related. Finally, it requires cross-referencing within footnotes to enable financial statement users to locate important information about derivative instruments. Effective January 1, 2009, we adopted the provisions of ASC Topic 815, and the adoption did not have a material impact on our consolidated financial statements. See Note 4. Price Risk Management Activities for further discussion.

In April 2009, the FASB issued guidance which amends disclosures about fair values of financial instruments and interim financial reporting to require disclosures about fair value of financial instruments in interim financial statements. This guidance is contained in ASC Topic 825, “Financial Instruments” (“ASC Topic 825”). We adopted the provisions of ASC Topic 825 on June 30, 2009 and the adoption did not have a material impact on our consolidated financial statements.

In May 2009, the FASB issued general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This guidance is contained in ASC Topic 855, “Subsequent Events” (“ASC Topic 855”). In particular, this guidance sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. In accordance with this guidance, an entity should apply the requirements to interim or annual financial periods ending after June 15, 2009. We adopted the provisions of ASC Topic 855 effective June 30, 2009 and the adoption did not have a material impact on our financial statements. The date through which subsequent events have been evaluated is November 4, 2009, the date on which the financial statements were issued. See Note 11. Subsequent Event for further discussion.

9

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
(c)  
New Pronouncements Issued But Not Yet Adopted:
 
In December 2008, the SEC published a Final Rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor, (2) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect future impairment and depletion calculations. The new disclosure requirements are effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We have not yet determined the impact of this Final Rule, which will vary depending on changes in commodity prices, on our disclosures, financial position, or results of operations.

In June 2009, the FASB issued guidance to change financial reporting by enterprises involved with variable interest entities (“VIEs”). The standard replaces the quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a VIE with an approach focused on identifying which enterprise has the power to direct the activities of a VIE and the obligation to absorb losses of the entity or the right to receive the entity’s residual returns. This standard will be effective for us on January 1, 2010. We do not have any interests in variable interest entities; therefore, we do not anticipate that this standard will have any impact on our consolidated financial statements.

In August 2009, the FASB issued Accounting Standards Update No. 2009-05 (“ASC Update 2009-05”), an update to ASC Topic 820. This update provides amendments to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. Among other provisions, this update provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the valuation techniques described in ASC Update 2009-05. ASC Update 2009-05 will become effective for our annual financial statements for the year ended December 31, 2009. We have not determined the impact that this update may have on our financial statements.

(d)  
Use of Estimates:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and oil reserves and related cash flow estimates used in impairment tests and fair value calculations of natural gas and oil properties, the fair value of derivative contracts and asset retirement obligations, accrued natural gas, natural gas liquids and oil revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization, and accretion. Actual results could differ from those estimates.

2.  
Acquisitions

On December 21, 2007, we entered into a Purchase and Sale Agreement with the Apache Corporation for the purchase of certain oil and natural gas properties located in ten separate fields in the Permian Basin of west Texas and southeastern New Mexico. We refer to this acquisition as the Permian Basin acquisition. The purchase price for said assets was $78.3 million with an effective date of October 1, 2007. We completed this acquisition on January 31, 2008 for an adjusted purchase price of $73.4 million, subject to customary post closing adjustments. The post closing adjustments reduced the final purchase price to $71.5 million and included a purchase price adjustment of $6.8 million for the cash flow from the acquired properties for the period between the effective date, October 1, 2007, and the final settlement date. As part of this acquisition, we assumed fixed-price oil swaps covering approximately 90% of the estimated proved developed producing oil reserves through 2011 at a weighted average price of $87.29. The fair value of these fixed-price oil swaps was a liability of $1.1 million at January 31, 2008. This acquisition was funded with borrowings under our existing reserve-based credit facility.
 
On July 18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro Drilling, Ltd. (“Segundo”), a wholly- owned subsidiary of the Lewis Energy Group, for the acquisition of certain natural gas and oil properties located in the Dos Hermanos Field in Webb County, Texas. We refer to this acquisition as the South Texas acquisition. The purchase price for said assets was $53.4 million with an effective date of June 1, 2008. We completed this acquisition on July 28, 2008 for an adjusted purchase price of $51.4 million, subject to customary post-closing adjustments to be determined. This acquisition was funded with $30.0 million of borrowings under our reserve-based credit facility and through the issuance of 1,350,873 common units of the Company valued at $21.4 million. Upon closing this transaction, we assumed natural gas swaps and collars based on Houston Ship Channel pricing for approximately 85% of the estimated gas production from existing producing wells in the acquired properties for the period beginning July 2008 through December 2011 which had a fair value of $3.6 million on July 28, 2008.

10

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
The following unaudited pro-forma results for the three and nine months ended September 30, 2008 show the effect on our consolidated results of operations as if the Permian Basin acquisition and the South Texas acquisition had occurred on January 1, 2008. The pro-forma results for the 2008 periods presented are the results of combining our statement of operations with the revenues and direct operating expenses of the oil and gas properties acquired adjusted for (1) assumption of asset retirement obligations and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, (3) interest expense on additional borrowings necessary to finance the acquisition, and (4) the impact of common units issued to partially finance the July 2008 acquisition. The pro-forma information is based upon these assumptions, and is not necessarily indicative of future results of operations:

   
Pro-forma
(in thousands, except per unit data)
(unaudited)
 
   
Three Months Ended 
September 30, 2008
   
Nine Months Ended
September 30, 2008
 
Total revenues
  $ 85,166     $ 48,181  
Net income
  $ 72,138     $ 11,840  
Net income per unit:
               
    Common & Class B units – basic
  $ 5.74     $ 0.94  
Common & Class B units – diluted
  $ 5.74     $ 0.94  
 
 
On July 17, 2009, we entered into a Purchase and Sale Agreement with Segundo for the acquisition of certain natural gas and oil properties located in the Sun TSH Field in La Salle County, Texas. We refer to this acquisition as the Sun TSH acquisition. The purchase price for said assets was $52.3 million with an effective date of July 1, 2009. We completed this acquisition on August 17, 2009 for an adjusted purchase price of $50.5 million, subject to customary post-closing adjustments to be determined. The adjusted purchase price was $50.5 million after consideration of preliminary purchase price adjustments of approximately $1.8 million, which included the settlement of a derivative contract for the latter part of August 2009 in the amount of $0.3 million. This acquisition was funded with borrowings under our reserve-based credit facility and proceeds from the Company’s public equity offering of 3.5 million common units completed on August 17, 2009. Upon closing this transaction, we assumed natural gas puts and swaps based on NYMEX pricing for approximately 61% of the estimated gas production from existing producing wells in the acquired properties for the period beginning August 2009 through December 2010, which had a fair value of $4.1 million on the closing date. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $5.9 million, calculated in the following table. The gain resulted from the changes in natural gas and oil prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the consolidated statement of operations.

   
(in thousands)
 
Fair value of assets and liabilities acquired:
     
Natural gas and oil properties
  $ 54,942  
Derivative assets
    4,128  
Other currents assets
    187  
Accrued expenses
    (298 )
Asset retirement obligations
    (2,254 )
Total fair value of assets and liabilities acquired
    56,705  
         
Fair value of consideration transferred
    50,827  
         
Gain on acquisition of natural gas and oil properties
  $ 5,878  

 

11

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
The following unaudited pro-forma results for the three and nine months ended September 30, 2009 and September 30, 2008 show the effect on our consolidated results of operations as if this acquisition had occurred on January 1, 2009 and on January 1, 2008, respectively. The pro-forma results for the 2009 and 2008 periods presented are the results of combining our statement of operations with the revenues and direct operating expenses of the oil and gas properties acquired adjusted for (1) assumption of asset retirement obligations and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, and (3) interest expense on additional borrowings necessary to finance the acquisition. The pro-forma information is based upon these assumptions, and is not necessarily indicative of future results of operations:
 
   
Pro-forma
(in thousands, except per unit data)
(unaudited)
 
   
Three Months Ended
September 30,
 
 Nine Months Ended
September 30,
   
     2009      2008      2009     2008    
Total revenues
  $ 8,156     $ 91,959     $ 41,880     $ 62,852    
Net income (loss)
  $ 1,858     $ 77,997     $ (53,002 )   $ 26,814    
Net income (loss) per unit:
                                 
    Common & Class B units – basic
  $ 0.11     $ 4.73     $ (3.21 )   $ 1.63    
Common & Class B units – diluted
  $ 0.11     $ 4.73     $ (3.21 )   $ 1.63    

 
3.  
Credit Facility and Long-Term Debt

Our credit facility and long-term debt consisted of the following:
 
 
     
   
 
Amount Outstanding
(in thousands)
   
Description
  Interest   Rate
Maturity Date
 
September 30,
2009
   
December 31,
2008
   
Senior secured reserve-based credit facility
Variable (1)
October 1, 2012
  $ 123,500     $ 135,000    
 
         (1) Variable interest rate was 2.7% and 3.8% at September 30, 2009 and December 31, 2008, respectively.
 
Senior Secured Reserve-Based Credit Facility
 
In January 2007, we entered into a four-year revolving credit facility (“reserve-based credit facility”) with Citibank, N.A. and BNP Paribas. All of our Predecessor’s outstanding debt was repaid with borrowings under this reserve-based credit facility. The available credit line (“Borrowing Base”) is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value (as determined by independent petroleum engineers) of estimated future net cash flows from certain of our proved natural gas, natural gas liquids and oil reserves. The reserve-based credit facility is secured by a first lien security interest in all of our natural gas and oil properties. Additional borrowings were made in January 2008 pursuant to the acquisition of natural gas and oil properties in the Permian Basin. In February 2008, our reserve-based credit facility was amended and restated to extend the maturity from January 3, 2011 to March 31, 2011, increase the facility amount from $200.0 million to $400.0 million, increase our borrowing base from $110.5 million to $150.0 million and add two additional financial institutions as lenders, Wachovia Bank, N.A. and The Bank of Nova Scotia. In May 2008, our reserved-based credit facility was amended in response to a potential acquisition that, ultimately, did not occur.  As a result, none of the provisions included in this amendment went into effect. In October 2008, we amended our reserve-based credit facility, which set our borrowing base under the facility at $175.0 million pursuant to our semi-annual redetermination and added a new lender, BBVA Compass Bank. In February 2009, our reserve-based credit facility was amended to allow us to repurchase up to $5.0 million of our own units. In May 2009, our borrowing base was set at $154.0 million pursuant to our semi-annual redetermination. In June 2009, a fourth amendment to our reserve-based credit facility was entered into which temporarily increased the percentage of outstanding indebtedness for which interest rate derivatives could be used. The percentage was increased from 75% to 85% but was to revert back to 75% in one year at June 2010. In August 2009, our reserve-based credit facility was amended and restated to (1) extend the maturity from March 31, 2011 to October 1, 2012, (2) increase our borrowing base from $154.0 million to $175.0 million, (3) increase our borrowing costs, (4) permanently allow 85% of our outstanding indebtedness to be covered under interest rate derivatives, and (5) add two financial institutions as lenders, Comerica Bank and Royal Bank of Canada. Our indebtedness under the reserve-based credit facility totaled $123.5 million at September 30, 2009. In October 2009, our reserve-based credit facility was amended, See Note 10. Subsequent Event for further discussion.

12

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
Interest rates under the reserve-based credit facility are based on Eurodollar (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At September 30, 2009 the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:
 
Borrowing Base Utilization Percentage
 
<50%
 
>50% <75%
 
>75% <90%
 
>90%
 
Eurodollar Loans
 
2.25%
 
2.50%
 
2.75%
 
3.00%
 
ABR Loans
 
1.25%
 
1.50%
 
1.75%
 
2.00%
 
Commitment Fee Rate
 
0.50%
 
0.50%
 
0.50%
 
0.50%
 
Letter of Credit Fee
 
2.25%
 
2.50%
 
2.75%
 
3.00%
 

Our reserve-based credit facility contains a number of customary covenants that require us to maintain certain financial ratios, limit our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets, or make distributions to our unitholders when our outstanding borrowings exceed 90% of our borrowing base. At September 30, 2009, we were in compliance with our debt covenants. 

4.  
Price Risk Management Activities

We have entered into derivative contracts with counterparties that are also lenders under our reserve-based credit facility, Citibank N.A., BNP Paribas, The Bank of Nova Scotia, and Wells Fargo Bank, N.A. (also under the name of Wachovia Bank, N.A.), to hedge price risk associated with a portion of our natural gas and oil production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Under fixed-priced commodity swap agreements, we receive a fixed price on a notional quantity in exchange for paying a variable price based on a market index, such as the Columbia Gas Appalachian Index (“TECO Index”), Henry Hub, or Houston Ship Channel for natural gas production and the West Texas Intermediate Light Sweet for oil production. Under put option agreements, we pay the counterparty an option premium, equal to the fair value of the option at the purchase date. At settlement date we receive the excess, if any, of the fixed floor over floating rate. Under collar contracts, we pay the counterparty if the market price is above the ceiling price, and the counterparty pays us if the market price is below the floor price on a notional quantity. The collars and put options for natural gas are settled based on the NYMEX price for natural gas at Henry Hub or Houston Ship Channel.

Under ASC Topic 815 “Derivatives and Hedging,” all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the consolidated balance sheets to the extent the hedge is effective.  Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges or gains (losses) on interest rate derivative contracts in the period that the related production is delivered or the contract settles.  The unrealized gains (losses) on derivative contracts that do not qualify for hedge accounting treatment are recorded as gains (losses) on other commodity derivative contracts or gains (losses) on interest rate derivative contracts in the consolidated statements of operations.

In February 2008, as part of the Permian Basin acquisition, we assumed fixed-price oil swaps covering approximately 90% of the estimated proved developed producing oil production through 2011 at a weighted average price of $87.29. Also, in February 2008, we sold calls (or set a ceiling price) which effectively collared 2,000,000 MMBtu of gas production in 2008 through 2009 which was previously only subject to a put (or price floor), we reset the price on 2,387,640 MMBtu of natural gas swaps settling in 2010 from $7.53 to $8.76 per MMBtu, and we entered into a 2012 fixed-price oil swap at $80.00 for 87% of our estimated proved developed production. In April 2008, we reset the price on 800,000 MMBtu of natural gas puts settling from May 1, 2008 to December 31, 2008 from $7.50 to $9.00 per MMBtu at a cost to us of $0.3 million which was funded with cash on hand. In July 2008, in connection with the South Texas acquisition, we assumed natural gas swaps and collars based on Houston Ship Channel pricing for approximately 85% of the estimated gas production from our existing producing wells for the period beginning July 2008 through December 2011.

In February 2009, we liquidated our 2012 oil swap and entered into new 2010 and 2011 natural gas swap and collar transactions. Specifically, a fixed price NYMEX natural gas swap for January through September 2010 and April through September 2011 at $8.04 and $7.85, respectively, was executed for 2,000 MMBtu/day. In addition, a 2,000 MMBtu/day NYMEX natural gas collar with a floor price of $7.50 and a ceiling price of $9.00 for October 2010 through March 2011 and October 2011 through December 2011 was executed. These natural gas derivatives were obtained at prices above the then current market by using the proceeds of the liquidation of the 2012 oil swap.

13

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
In August 2009, in connection with the Sun TSH acquisition, we assumed natural gas puts and swaps based on NYMEX pricing for approximately 61% of the estimated gas production from existing producing wells in the acquired properties for the period beginning August of 2009 through December 2010. In addition, concurrent with the execution of the purchase and sale agreement, the Company entered into a collar for certain volumes in 2010 and a series of collars for a substantial portion of the expected gas production for 2011 at prices above the then current market with a total cost to the Company of $3.1 million, which was financed through deferred premiums.  

As of September 30, 2009, we have open commodity derivative contracts covering our anticipated future production as follows:
 
Swap Agreements
 
 
Gas
 
Oil
 
Contract Period  
MMBtu
 
Weighted
Average
Fixed Price
 
Bbls
 
WTI
Price
 
October 1, 2009 - December 31, 2009  
864,806
 
$
9.34
 
44,000
 
$
87.23
 
January 1, 2010 - December 31, 2010  
4,731,040
 
$
8.66
 
164,250
 
$
85.65
 
January 1, 2011 - December 31, 2011  
3,328,312
 
$
7.83
 
151,250
 
$
85.50
 

Put Option Contracts

Contract Period
  Volume in MMBtu
 
Purchased NYMEX
Price Floor
 
October 1, 2009 - December 31, 2009  
651,446
 
$
7.85
 

Collars

   
 
Gas
   
Oil
 
   
 
MMBtu
   
Floor
   
Ceiling
   
Bbls
   
Floor
   
Ceiling
 
Production Period:  
                                   
October 1, 2009 - December 31, 2009  
    249,999     $ 7.50     $ 9.00       9,200     $ 100.00     $ 127.00  
January 1, 2010 - December 31, 2010
    1,607,500     $ 7.73     $ 8.92           $     $  
January 1, 2011 - December 31, 2011
    1,933,500     $ 7.34     $ 8.44           $     $  
 
Interest Rate Swaps

We enter into interest rate swap agreements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate exposures to fixed interest rates.

From December 2007 through March 2008, we entered into interest rate swap agreements which effectively fixed the LIBOR rate at 2.66 % to 3.88% on $60.0 million of borrowings. In August 2008, we entered into two interest rate basis swaps which changed the reset option from three month LIBOR to one month LIBOR on the total $60.0 million of outstanding interest rate swaps. By doing so, we reduced our borrowing cost based on three month LIBOR by 14 basis points on $20.0 million of borrowings for a one year period starting September 10, 2008 and 12 basis points on $40.0 million of borrowings for a one year period starting October 31, 2008. As a result of these two basis swaps, we chose to de-designate the interest rate swaps as cash flow hedges as the terms of the new contracts no longer matched the terms of the original contracts, thus causing the interest rate hedges to be ineffective. Beginning in the third quarter of 2008, we recorded changes in the fair value of our interest rate derivatives in current earnings under gains (losses) on interest rate derivative contracts. The net unrealized gain at June 30, 2008 related to the de-designated cash flow hedges is reported in accumulated other comprehensive income and later reclassified to earnings in the month in which the transactions settle. In December 2008, we amended three existing interest rate swap agreements and entered into one new agreement which fixed the LIBOR rate at 1.85% on $10.0 million of borrowings through December 2010. The first amended agreement reduced the fixed LIBOR rate from 3.88% to 3.35% on $20.0 million and the maturity was extended two additional years to December 10, 2012. In addition, the second amended agreement reset the notional amount on the March 31, 2011 swap from $10.0 million to $20.0 million and also reduced the rate from 2.66% to 2.08%. The third amended agreement reset the notional amount on the January 31, 2011 swap from $10.0 million to $20.0 million, reduced the rate from 3.00% to 2.38% and also extended the maturity two additional years to 2013.

14

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
As of September 30, 2009, we have open interest rate derivative contracts as follows:

   
 Notional
 Amount
(in thousands)
 
Fixed
Libor
Rates
 
Period:
           
October 1, 2009 to December 18, 2010
 
$
10,000
 
1.50
%
October 1, 2009 to December 20, 2010
 
$
10,000
 
1.85
%
October 1, 2009 to January 31, 2011
 
$
20,000
 
3.00
%
October 1, 2009 to March 31, 2011
 
$
20,000
 
2.08
%
October 1, 2009 to December 10, 2012
 
$
20,000
 
3.35
%
October 1, 2009 to January 31, 2013
 
$
20,000
 
2.38
%
October 1, 2009 to October 31, 2009 (Basis Swap)
 
$
40,000
 
LIBOR 1M vs. LIBOR 3M
 

Balance Sheet Presentation

Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis.

   
September 30, 2009
December 31, 2008
 
   
(in thousands)
 
Assets:
           
Commodity derivatives
  $ 30,734     $ 39,875  
Interest rate swaps
           
    $ 30,734     $ 39,875  
Liabilities:
               
Commodity derivatives
  $ (4,739 )   $ (1,942 )
Interest rate swaps
    (2,459 )     (2,799 )
    $ (7,198 )   $ (4,741 )

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our reserve-based credit facility (See Note 3. Credit Facilities and Long-Term Debt for further discussion) which is secured by our natural gas and oil properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $30.7 million at September 30, 2009.

15

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments only with counterparties that are also lenders in our reserve-based credit facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis. In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated as of September 30, 2009.  
 
Gain (Loss) on Derivatives
 
Gains and losses on derivatives are reported on the consolidated statement of operations in “gain (loss) on other commodity derivative contracts” and “loss on interest rate derivative contracts” and include realized and unrealized gains (losses). Realized gains (losses) represent amounts related to the settlement of derivative instruments. Unrealized gains (losses) represent the change in fair value of the derivative instruments that will settle in the future and are non-cash items.
 
The following presents our reported gains and losses on derivative instruments (in thousands):

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
Realized gains (losses):
                       
Other commodity derivatives
  $ 8,010     $ (2,989 )   $ 23,794     $ (10,410 )
Interest rate swaps
    (506 )     (39     (1,240 )     (90 )
    $ 7,504     $ (3,028 )   $ 22,554     $ (10,500 )
Unrealized gains (losses):
                               
Other commodity derivatives
  $ (12,220 )   $ 66,353     $ (16,492 )   $ (6,043 )
Interest rate swaps
    (575 )     (420     387       (420 )
    $ (12,795 )   $ 65,933     $ (16,105 )   $ (6,463 )
Total gains (losses):
                               
Other commodity derivatives
  $ (4,210 )   $ 63,364     $ 7,302     $ (16,453 )
Interest rate swaps
    (1,081 )     (459 )     (853 )     (510 )
    $ (5,291 )   $ 62,905     $ 6,449     $ (16,963 )
 
5.  
Fair Value Measurements

As discussed in Note 1. Summary of Significant Accounting Policies (b), we adopted ASC Topic 820 for financial assets and financial liabilities as of January 1, 2008 and for non-financial assets and liabilities as of January 1, 2009. ASC Topic 820 does not expand the use of fair value measurements, but rather, provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, and to long-lived assets carried at fair value subsequent to an impairment write-down. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the consolidated balance sheet, as well as to supplemental fair value information about financial instruments not carried at fair value.
 
The estimated fair values of our financial instruments closely approximate the carrying amounts as discussed below:

Cash and cash equivalents, accounts receivable, other current assets, accounts payable, payables to affiliates, deferred swap liability, phantom unit compensation accrual, accrued ad valorem taxes and accrued expenses. The carrying amounts approximate fair value due to the short maturity of these instruments.

Long-term debt. The carrying amount of our reserve-based credit facility approximates fair value because our current borrowing rate does not materially differ from market rates for similar bank borrowings.

We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis. This includes natural gas, oil and interest rate derivatives contracts. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction. These assumptions include certain factors not consistently provided for previously by those companies utilizing fair value measurement; examples of such factors would include our own credit standing (when valuing liabilities) and the buyer’s risk premium. In adopting ASC Topic 820, we determined that the impact of these additional assumptions on fair value measurements did not have a material effect on our financial position or results of operations.
16

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process.

The standard describes three levels of inputs that may be used to measure fair value:  
     
Level 1
 
Quoted prices for identical instruments in active markets.
     
Level  2
 
Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.
     
Level 3
 
Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.

As required by ASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Our commodity derivative instruments consist of swaps and options. We estimate the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest rate swap market data. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows. We have classified the fair values of all its derivative contracts as Level 2.

Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below:

   
 
September 30, 2009
(in thousands)
 
   
 
Fair Value Measurements Using
   
Assets/Liabilities
 
   
 
Level 1
   
Level 2
   
Level 3
   
at Fair value
 
Assets:
                       
Commodity price derivative contracts  
  $     $ 26,366     $     $ 26,366  
Total derivative instruments  
  $     $ 26,366     $     $ 26,366  
                                 
Liabilities:
                               
Commodity price derivative contracts  
  $     $ (371 )   $     $ (371 )
Interest rate derivative contracts  
          (2,459 )           (2,459 )
Total derivative instruments  
  $     $ (2,830 )   $     $ (2,830 )

17

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
On January 1, 2009, we adopted the previously-deferred provisions of ASC Topic 820 for nonfinancial assets and liabilities, which are comprised primarily of asset retirement costs and obligations initially measured at fair value in accordance with ASC Topic 410 Subtopic 20 “Asset Retirement Obligations” (“ASC Topic 410-20”).  These assets and liabilities are recorded at fair value when incurred but not re-measured at fair value in subsequent periods.  We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination.  A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 6, in accordance with ASC Topic 410-20.  During the nine months ended September 30, 2009, in connection with natural gas and oil properties acquired in the Sun TSH acquisition, we incurred and recorded asset retirement obligations totaling $2.3 million at fair value. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount.  Inputs to the valuation include: (1) estimated plug and abandon cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate (2.4%); and (4) the ten year average inflation factor (2.4%).  The adoption of ASC Topic 820 on January 1, 2009, as it relates to nonfinancial assets and nonfinancial liabilities, did not have a material impact on our financial position or results of operations.

6.  
Asset Retirement Obligations

The asset retirement obligations as of September 30 reported on our consolidated balance sheets and the changes in the asset retirement obligations for the nine months ended September 30, were as follows:

   
2009
   
2008
 
   
(in thousands)
 
     
 
Asset retirement obligations at January 1,
  $ 2,134     $ 190  
Liabilities added during the current period
    2,254       2,155  
Accretion expense
    86       59  
Revisions of estimates
    (341 )      
Asset retirement obligation at September 30,
  $ 4,133     $ 2,404  

7.  
Related Party Transactions

In Appalachia, we rely on Vinland to execute our drilling program, operate our wells and gather our natural gas. Pursuant to amended agreements effective March 1, 2009, we reimburse Vinland $95 per well per month (in addition to normal third party operating costs) for operating our current natural gas and oil properties in Appalachia under a Management Services Agreement (“MSA”) which costs are reflected in our lease operating expenses. Also, pursuant to amended agreements effective March 1, 2009, Vinland receives a fee based upon the actual costs incurred by Vinland to provide gathering and transportation services plus a $0.05 per Mcf margin. This transportation fee only encompasses transporting the natural gas to third party pipelines at which point additional transportation fees to natural gas markets would apply. These transportation fees are outlined under a Gathering and Compression Agreement (“GCA”) with Vinland and are reflected in our lease operating expenses. Costs incurred under the MSA were $0.5 million and $0.1 million for the three months ended September 30, 2009 and 2008 and $1.2 million and $0.4 million for the nine months ended September 30, 2009 and 2008, respectively. Costs incurred under the GCA were $0.4 million and $0.2 million for the three months ended September 30, 2009 and 2008 and $0.9 million and $0.8 million for the nine months ended September 30, 2009 and 2008, respectively. A payable of $0.9 million and $2.6 million, respectively, is reflected on our September 30, 2009 and December 31, 2008 consolidated balance sheets in connection with these agreements and direct expenses incurred by Vinland related to the drilling of new wells and operations of all of our existing wells in Appalachia.

On April 1, 2009, we and our wholly-owned subsidiary, TEC, exchanged several wells and lease interests (the “Asset Exchange”) with Vinland, Appalachian Royalty Trust, LLC, and Nami Resources Company, L.L.C. (collectively, the “Nami Companies”). Each of the Nami Companies is beneficially owned by Majeed S. Nami, who, as of September 30, 2009, beneficially owned 19.5% of our common units representing limited liability company interests. In the Asset Exchange, we assigned well, strata and leasehold interests with internal estimated future cash flows of approximately $2.7 million discounted at ten percent, and received well, strata, and leasehold interests with an approximately equal value; therefore no gain or loss was recognized.

18

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
8.  
Common Units and Net Income per Unit

Basic earnings per unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”), by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during the period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents.  We use the treasury stock method to determine the dilutive effect. As of September 30, 2009, we have two classes of units outstanding:  (i) units representing limited liability company interests (“common units”) listed on NYSE under the symbol VNR and (ii) Class B units, issued to management and an employee as discussed in Note 9. Unit-Based Compensation. The Class B units participate in distributions and no forfeiture is expected; therefore, all Class B units were considered in the computation of basic earnings per unit. The 175,000 options granted to officers under our long-term incentive plan had no dilutive effect as the exercise price was higher than the market price at September 30, 2009; therefore, they have been excluded from the computation of diluted earnings per unit. In addition, the phantom units granted to officers under our long-term incentive plan will have no dilutive effect unless there is a liability at December 31, 2009 and if the officers elect to have the liability satisfied in units; therefore, they have been excluded from the computation of diluted earnings per unit.

In accordance with ASC Topic 260, dual presentation of basic and diluted earnings per unit has been presented in the consolidated statements of operations for the three and nine months ended September 30, 2009 and 2008 including each class of units issued and outstanding at that date: common units and Class B units. Net income (loss) per unit is allocated to the common units and the Class B units on an equal basis. 

9.  
Unit-Based Compensation

In April 2007, the sole member at that time reserved 460,000 restricted Class B units in VNR for issuance to employees. Certain members of management were granted 365,000 restricted Class B units in VNR in April 2007, which vested two years from the date of grant. In addition, another 55,000 restricted VNR Class B units were issued in August 2007 to two other employees that were hired in April and May of 2007, which will vest after three years. The remaining 40,000 restricted Class B units are available to be awarded to new employees or members of our board of directors as they are retained.

In October 2007, one board member was granted 5,000 common units and in February 2008, three board members were granted 5,000 common units each of which vested after one year. Additionally, in October 2007, two officers were granted options to purchase an aggregate of 175,000 units under our long-term incentive plan with an exercise price equal to the initial public offering price of $19.00 which vested immediately upon being granted and had a fair value of $0.1 million on the date of grant. The grant date fair value for these option awards was calculated in accordance with ASC Topic 718 “Compensation- Stock Compensation” (“ASC Topic 718”), by calculating the Black-Scholes value of each option, using a volatility rate of 12.18%, an expected dividend yield of 8.95% and a discount rate of 5.12%, and multiplying the Black-Scholes value by the number of options awarded.

On January 1, 2009, in accordance with their previously negotiated employment agreements, phantom units were granted to two officers in amounts equal to 1% of our units outstanding at January 1, 2009. The amount will be paid in either cash or at the officer’s election, units and will equal the appreciation in value of the units, if any, from the date of the grant until the determination date (December 31, 2009), plus cash distributions paid on the units, less an 8% hurdle rate. As of September 30, 2009, an accrued liability and non-cash compensation expense totaling $3.0 million has been recognized for the unrealized fair value of these phantom units.

On January 7, 2009, four board members were granted 5,000 common units each of which will vest after one year and on February 27, 2009, employees were granted 17,950 units that will vest after one year.

These common units, Class B units, options and phantom units were granted as partial consideration for services to be performed under employment contracts and thus will be subject to accounting for these grants under ASC Topic 718. The fair value of restricted units issued is determined based on the fair market value of common units on the date of the grant. This value is amortized over the vesting period as referenced above. A summary of the status of the non-vested units as of September 30, 2009 is presented below:

19

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
 
   
Number of 
Non-vested Units
   
Weighted Average
Grant Date Fair Value
 
   
 
   
   
 
Non-vested units at December 31, 2008
    440,000     $ 18.10  
Granted
    37,950     $ 8.07  
Vested
    (385,000 )   $ (17.97 )
Non-vested units at September 30, 2009
    92,950     $ 14.54  

At September 30, 2009, there was approximately $0.3 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 0.5 years. Our consolidated statement of operations reflects non-cash unit-based compensation of $1.3 million and $5.3 million in the selling, general and administrative line item, of which $0.8 million and $3.0 million relates to the unrealized fair value of phantom units granted to officers for the three and nine months ended September 30, 2009, respectively. Non-cash unit-based compensation was $0.8 million and $2.7 million for the three and nine months ended September 30, 2008, respectively. There was no expense related to the fair value of phantom units granted to officers in the three or nine month period ended September 30, 2008.

10.  
Shelf Registration Statement

During the third quarter 2009, we filed a registration statement with the SEC which registered offerings of up to $300.0 million of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

In August 2009, we completed an offering of 3.9 million shares of its common units. The units were offered to the public at a price of $14.25 per unit. We received net proceeds of approximately $53.2 million from the offering, after deducting underwriting discounts of $2.4 million and offering costs of $0.5 million. As a result of the offering, we have approximately $244.0 million remaining available under our 2009 shelf registration statement as of September 30, 2009.

11.  
Subsequent Event

On October 1, 2009, we entered into the First Amendment to our Second Amended and Restated Credit Agreement, which reduced our borrowing base under the reserve-based credit facility from $175.0 million to $170.0 million pursuant to our semi-annual redetermination and changed the definition of majority lenders from 75% to 66.67%. All other terms under the reserve-based credit facility remained the same.

 
20

 
 
The following discussion and analysis should be read in conjunction with the financial statements and related notes presented in Item 1 of this Quarterly Report on Form 10-Q and information disclosed in our 2008 Annual Report on Form 10-K.
 
Forward-Looking Statements
 
This report contains “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995. Statements included in this quarterly report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.
 
Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in the Risk Factor section of the 2008 Annual Report on Form 10-K and this Quarterly Report on Form 10-Q, and those set forth from time to time in our filings with the SEC, which are available on our website at www.vnrllc.com and through the SEC’s Electronic Data Gathering and Retrieval System (“EDGAR”) at http://www.sec.gov.
 
All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.
 
Overview
 
We are a publicly-traded limited liability company focused on the acquisition and development of mature, long-lived natural gas and oil properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase our quarterly cash distributions through the acquisition of new natural gas and oil properties. Our properties are located in the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee, the Permian Basin, primarily in west Texas and southeastern New Mexico, and in South Texas.
 
We owned working interests in 1,587 gross (1,132 net) productive wells at September 30, 2009, and our average net production for the twelve months ended December 31, 2008 and for the nine months ended September 30, 2009 was 16,206 Mcfe per day and 18,623 Mcfe per day, respectively. In addition to these productive wells, we own leasehold acreage allowing us to drill new wells. We have an approximate 40% working interest in the known producing horizons in approximately 96,800 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. Furthermore, in South Texas, we own working interest ranging from 45-50% in approximately 13,303 undeveloped acres surrounding our existing wells. Based on internal reserve estimates at September 30, 2009, approximately 28%, or 35.9 Bcfe, of our estimated proved reserves were attributable to our working interests in undeveloped acreage.

Disruption to Functioning of Capital Markets

Multiple events during 2008 and 2009 involving numerous financial institutions effectively restricted liquidity within the capital markets throughout the United States and around the world. While capital markets remain volatile, efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector appears to have improved the situation. As evidenced by our recent successful equity offering, successful amendment of our reserve-based credit facility and recent successful equity and debt offerings by our peers, we believe that our access to capital has improved and we have been successful in improving our financial position to date.

During the first nine months of 2009, our unit price increased from a closing low of $6.35 on January 2, 2009 to a closing high of $16.44 on September 30, 2009. Also, during the nine months ended September 30, 2009, we did not drill any wells on our operated properties and there was limited drilling on non-operated properties. We intend to move forward with our development drilling program when market conditions allow for an adequate return on the drilling investment and only when we have sufficient liquidity to do so. Maintaining adequate liquidity may involve the issuance of debt and equity at less attractive terms, could involve the sale of non-core assets, and could require reductions in our capital spending. In the near-term we will focus on maximizing returns on existing assets by managing our costs and selectively deploying capital to improve existing conditions.

21

Permian Basin Acquisition

On December 21, 2007, we entered in to a Purchase and Sale Agreement with the Apache Corporation for the purchase of certain oil and natural gas properties located in ten separate fields in the Permian Basin of west Texas and southeastern New Mexico. The purchase price for said assets was $78.3 million with an effective date of October 1, 2007. We completed this acquisition on January 31, 2008 for an adjusted purchase price of $73.4 million, subject to customary post closing adjustments. The post closing adjustments reduced the final purchase price to $71.5 million and included a purchase price adjustment of $6.8 million for the cash flow from the acquired properties for the period between the effective date, October 1, 2007, and the final settlement date. This acquisition was funded with borrowings under our reserve-based credit facility. Through this acquisition, we acquired working interests in 390 gross wells (67 net wells), 49 of which we operate. We manage the operations of these assets from two district offices, one in Lovington, New Mexico and the other in Christoval, Texas. Our operating focus has been on maximizing existing production and looking for complementary acquisitions that we can add to this operating platform. At September 30, 2009, based on internal reserve estimates, we own 3.5 million barrels of oil equivalent, 87% of which is oil and 88% of which is proved developed producing.

South Texas Acquisition

On July 18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro Drilling, Ltd. (“Segundo”), a wholly- owned subsidiary of the Lewis Energy Group, L. P. (“Lewis”) for the acquisition of certain natural gas and oil properties located in the Dos Hermanos Field in Webb County, Texas. The purchase price for said assets was $53.4 million with an effective date of June 1, 2008. We completed this acquisition on July 28, 2008 for an adjusted purchase price of $51.4 million, subject to customary post-closing adjustments to be determined. This acquisition was funded with $30.0 million of borrowings under our reserve-based credit facility and through the issuance of 1,350,873 common units of the Company. In this purchase, we acquired an average of a 98% working interest in 91 producing wells and an average 47.5% working interest in approximately 4,705 gross acres with 41 identified proved undeveloped locations. An affiliate of Lewis operates all the properties and is contractually obligated to drill seven wells each year from 2009 through 2013 unless we mutually agree not to do so. Upon closing this transaction, we assumed natural gas swaps and collars based on Houston Ship Channel pricing for approximately 85% of the estimated gas production from existing producing wells in the acquired properties for the period beginning July 2008 through December 2011 which had a fair value of $3.6 million on July 28, 2008. At September 30, 2009, based on internal reserve estimates, we own 20.0 Bcfe of proved reserves, 100% of which is natural gas and natural gas liquids and 56% of which is proved developed producing.

Sun TSH Acquisition

On July 17, 2009, we entered into a Purchase and Sale Agreement to acquire certain natural gas and oil properties located in the Sun TSH Field in La Salle County, Texas for $52.3 million with Segundo. Lewis will operate all of the wells acquired in this transaction. Based on the current net daily production of approximately 6,100 Mcfe, the properties have a reserve to production ratio of approximately 16 years. The acquisition had a July 1, 2009 effective date, was completed on August 17, 2009 for an adjusted purchase price of $50.5 million, and is subject to customary post-closing adjustments to be determined. The properties acquired have total estimated proved reserves of 34.9 Bcfe as of September 30, 2009, of which 96% is natural gas and natural gas liquids and 67% is proved developed producing. This acquisition was funded with borrowings under our reserve-based credit facility and proceeds from the Company’s public equity offering of 3.5 million common units completed on August 17, 2009.

At closing, we assumed natural gas puts and swaps based on NYMEX pricing for approximately 61% of the estimated gas production from existing producing wells in the acquired properties for the period beginning August of 2009 through December of 2010, which had a fair value of $4.1 million on the closing date. In addition, concurrent with the execution of the Purchase and Sale Agreement, we entered into a collar for certain volumes in 2010 and a series of collars for a substantial portion of the expected gas production for 2011 at prices above the then current market with a total cost to the Company of $3.1 million which was financed through deferred premiums. Inclusive of the hedges added, approximately 90% of the estimated gas production from existing producing wells in the acquired properties is hedged through 2011. A schedule of the hedges assumed and added is shown below:
 
 
Contract Period
 
Volume (MMBtu)
   
Price
 
Put and Swap Agreements Assumed:
           
August – December 2009
    765,000     $ 8.00  
January – December 2010
    949,000     $ 7.50  
Collars Added:
               
January – December 2010
    693,500     $ 7.50 - $8.50  
January – December 2011
    1,569,500     $ 7.31 - $8.31 (1)

 
(1)
Price is calculated based on weighted average pricing.

22

Reserve-Based Credit Facility
 
On January 3, 2007, we entered into a reserve-based credit facility which is available for our general limited liability company purposes, including, without limitation, capital expenditures and acquisitions. Our obligations under the reserve-based credit facility are secured by substantially all of our assets. Our initial borrowing base under the reserve-based credit facility was set at $115.5 million. However, the borrowing base was subject to $1.0 million reductions per month starting on July 1, 2007 through November 1, 2007, which resulted in a borrowing base of $110.5 million as reaffirmed in November 2007 pursuant to a semi-annual borrowing base redetermination. We applied $80.0 million of the net proceeds from our IPO in October 2007 to reduce our indebtedness under the reserve-based credit facility. In February 2008, our reserve-based credit facility was amended and restated to extend the maturity from January 3, 2011 to March 31, 2011, increase the facility amount from $200.0 million to $400.0 million, increase our borrowing base from $110.5 million to $150.0 million and add two additional financial institutions as lenders, Wachovia bank, N.A., and The Bank of Nova Scotia. Additional borrowings were made in January 2008 pursuant to the acquisition of natural gas and oil properties in the Permian Basin, and in July 2008 an additional $30.0 million was borrowed to fund a portion of the cash consideration paid in the South Texas acquisition. In May 2008, our reserve-based credit facility was amended in response to a potential acquisition that ultimately did not occur. As a result, none of the provisions included in this amendment went into effect. In October 2008, we amended our reserve-based credit facility which set our borrowing base under the facility at $175.0 million pursuant to our semi-annual redetermination and added a new lender, BBVA Compass Bank. In February 2009, a third amendment was entered into which amended covenants to allow us to repurchase up to $5.0 million of our own units. In May 2009, our borrowing base was set at $154.0 million pursuant to our semi-annual redetermination. In June 2009, a fourth amendment to our reserve-based credit facility was entered into which temporarily increased the percentage of outstanding indebtedness for which interest rate derivatives could be used. The percentage was increased from 75% to 85% but was to revert back to 75% in one year at June 2010. In August 2009, our reserve-based credit facility was amended and restated to (1) extend the maturity from March 31, 2011 to October 1, 2012, (2) increase our borrowing base from $154.0 million to $175.0 million, (3) increase our borrowing costs, (4) permanently allow 85% of our outstanding indebtedness to be covered under interest rate derivatives, and (5) add two financial institutions as lenders, Comerica Bank and Royal Bank of Canada. Indebtedness under the reserve-based credit facility totaled $123.5 million at September 30, 2009, and the applicable margins and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Percentage
 
<50%
 
>50% <75%
 
>75% <90%
 
>90%
 
Eurodollar Loans
 
2.25%
 
2.50%
 
2.75%
 
3.00%
 
ABR Loans
 
1.25%
 
1.50%
 
1.75%
 
2.00%
 
Commitment Fee Rate
 
0.50%
 
0.50%
 
0.50%
 
0.50%
 
Letter of Credit Fee
 
2.25%
 
2.50%
 
2.75%
 
3.00%
 

In October 2009, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which reduced our borrowing base under the reserve-based credit facility from $175.0 million to $170.0 million pursuant to our semi-annual redetermination and changed the definition of majority lenders from 75% to 66.67%. All other terms under the reserve-based credit facility remained the same.

Outlook
 
Our revenue, cash flow from operations, and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Multiple events during 2008 and 2009 involving numerous financial institutions effectively restricted liquidity within the capital markets throughout the United States and around the world. While capital markets remain volatile, efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector appears to have improved the situation. As evidenced by our recent successful equity offering, successful amendment of our reserve-based credit facility and recent successful equity and debt offerings by our peers, we believe that our access to capital has improved and we have been successful in improving our financial position to date.

Natural gas, natural gas liquids and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas, natural gas liquids and oil reserves that we can economically produce and our access to capital. We have mitigated the volatility on our cash flows through 2011 by implementing a hedging program on a portion of our proved producing and a portion of our total anticipated production during this time frame. As natural gas, natural gas liquids and oil prices fluctuate, we will recognize non-cash, unrealized gains and losses in our consolidated statement of operations related to the change in fair value of our commodity derivative contracts.
 
23

We face the challenge of natural gas, natural gas liquids and oil production declines. As a given well’s initial reservoir pressures are depleted, natural gas, natural gas liquids and oil production decreases, thus reducing our total reserves. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. During the nine months ended September 30, 2009, we did not drill any wells on our operated properties and there was limited drilling on non-operated properties. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals and voluntary reductions in capital spending in a low commodity price environment. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues and as a result, cash available for distribution. In accordance with our business plan, we intend to invest the capital necessary to maintain our production at existing levels over the long-term provided that it is economical to do so based on the commodity price environment. However, we cannot be certain that we will be able to issue equity securities on favorable terms, or at all, and we may be unable to refinance our reserve-based credit facility when it expires. Additionally, due to the significant decline in commodity prices, our borrowing base under our reserve-based credit facility may be redetermined such that it will not provide for the working capital necessary to fund our capital spending program and could affect our ability to make distributions. The next scheduled redetermination of our borrowing base is April 2010.
 
Results of Operations
 
The following table sets forth selected financial and operating data for the periods indicated (in thousands):

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2009(c)
   
2008(b)
   
2009(c)
   
2008(a)(b)
 
Revenues:
                       
Natural gas sales
  $ 4,742     $ 12,708     $ 15,500     $ 34,812  
Natural gas liquids sales
    1,136       601       1,811       824  
Oil sales
    5,446       7,530       12,619       20,057  
Natural gas, natural gas liquids and oil sales
    11,324       20,839       29,930       55,693  
Realized gain (loss) on commodity cash flow hedges
    (463 )     45       (1,737 )     616  
Realized gain (loss) on other commodity derivative contracts
    8,010       (2,989 )     23,794       (10,410 )
Unrealized gain (loss) on other commodity derivative contracts
    (12,220 )     66,353       (16,492 )     (6,043 )
Total revenues
  $ 6,651     $ 84,248     $ 35,495     $ 39,856  
Costs and expenses:
                               
Lease operating expenses
  $ 3,322     $ 3,485     $ 9,233     $ 7,800  
Depreciation, depletion, amortization, and accretion
    3,272       4,187       9,700       10,341  
Impairment of natural gas and oil properties
                63,818        
Selling, general and administrative expenses
    2,137       1,560       8,230       4,843  
Production and other taxes
    974       1,263       2,537       3,658  
Total costs and expenses
  $ 9,705     $ 10,495     $ 93,518     $ 26,642  
Other income and (expense):
                               
Interest expense, net
  $ (1,042 )   $ (1,485 )   $ (3,034 )   $ (3,847 )
Gain on acquisition of natural gas and oil properties
    5,878             5,878        
Realized loss on interest rate derivative contracts
  $ (506 )   $ (39 )   $ (1,240 )   $ (90 )
Unrealized gain (loss) on interest rate derivative contracts
  $ (575 )   $ (420 )   $ 387     $ (420 )

 
(a)
The Permian Basin acquisition closed on January 31, 2008 and, as such, only eight months of operations are included in the nine month period ended September 30, 2008.
 
(b)
The South Texas acquisition closed on July 28, 2008 and, as such, only two months of operations are included in the three month and nine month period ended September 30, 2008.
 
(c)
The Sun TSH acquisition closed on August 17, 2009 and, as such, only approximately one and a half months of operations are included in the three month and nine month period ended September 30, 2009.
 
24

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008
 
Revenues
 
Natural gas, natural gas liquids and oil sales decreased $9.5 million to $11.3 million during the three months ended September 30, 2009 as compared to the same period in 2008. The key revenue measurements were as follows:

   
Three Months Ended
September 30,
 
 
Percentage
Increase
(Decrease)
 
   
2009
 
2008
   
Net Natural Gas Production:
               
Appalachian gas (MMcf) 
   
773
 
923
 
(16)
%
Permian gas (MMcf) 
   
57
 
 
N/A
 
South Texas gas (MMcf)
   
196
 
160
(a)
23
%
Sun TSH gas (MMcf)
   
139
(b)
 
N/A
 
Total natural gas production (MMcf)
   
1,165
 
1,083
 
8
%
                 
Average Appalachian daily gas production (Mcf/day)
   
8,403
 
10,031
 
(16)
%
Average Permian daily gas production (Mcf/day)
   
617
 
 
N/A
 
Average South Texas daily gas production (Mcf/day)
   
2,136
 
2,463
(a)
(13)
%
Average Sun TSH daily gas production (Mcf/day)
   
3, 088
(b)
 
N/A
 
Average Vanguard daily gas production (Mcf/day)
   
14,244
 
12,494
 
 
 
                 
Average Natural Gas Sales Price per Mcf:
               
Net realized gas price, including hedges
  $
11.12
(c)
$10.84
(c) 
3
%
Net realized gas price, excluding hedges
  $
4.07
 
$10.94
 
(63)
%
                 
Net Oil Production:
               
Appalachian oil (Bbls) 
   
25,451
 
11,122
 
129
%
Permian oil (Bbls) 
   
57,525
 
54,924
 
5
%
Sun TSH oil (Bbls)
   
2,425
(b)
 
N/A
 
Total oil production (Bbls)
   
85,401
 
66,046
 
29
%
                 
Average Appalachian daily oil production (Bbls/day)
   
277
 
121
 
129
%
Average Permian daily oil production (Bbls/day)
   
625
 
597
 
5
%
Average Sun TSH daily oil production (Bbls/day)
   
54
(b)
 
N/A
 
Average Vanguard daily oil production (Bbls/day)
   
956
 
718
     
                 
Average Oil Sales Price per Bbl:
               
Net realized oil price, including hedges
  $
77.15
(c)
$93.26
(c)
(17)
%
Net realized oil price, excluding hedges
  $
63.76
 
$114.01
 
(44)
%
                 
Net Natural Gas Liquids Production:
               
Permian natural gas liquids (Gal) 
   
105,336
 
128,171
 
(18)
%
South Texas natural gas liquids (Gal) 
   
436,922
 
421,680
(a)
4
%
Sun TSH natural gas liquids (Gal)
   
848,954
(b)
 
N/A
 
Total natural gas liquids production (Gal)
   
1,391,212
 
549,851
 
153
%
                 
Average Permian daily natural gas liquids production (Gal/day)
   
1,145
 
1,393
 
(18)
%
Average South Texas daily natural gas liquids production (Gal/day)
   
4,749
 
6,487
(a)
(27)
%