Prior to the separation, our predecessor owned all of the assets that are currently owned by us and Vinland. As part of the separation of our operating company and Vinland, effective January 5, 2007, we conveyed to Vinland 60% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres in the AMI, 100% of our predecessor’s interest in an additional 125,000 undeveloped acres and certain coalbed methane rights located in the Appalachian Basin, the rights to any natural gas and oil located on our acreage at 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. 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 in the AMI and a contract right to receive approximately 99% of the net proceeds, after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of wells and overhead costs, from the sale of production from certain producing natural gas and oil wells, which accounted for approximately 5% of our pro forma estimated proved reserves as of March 31, 2007. In addition, we changed the name of our operating company from Nami Holding Company, LLC to Vanguard Natural Gas, LLC. Collectively, we refer to these events as the “Restructuring.”

 

 

In April 2007, we completed a private equity offering pursuant to which we issued 2,290,000 units to certain private investors, which we collectively refer to as the Private Investors, for $41.2 million. We used the net proceeds of this private equity offering to make a distribution to Majeed S. Nami, VNR’s largest unitholder, who used a portion of these funds to capitalize Vinland and also paid us $3.9 million to reduce outstanding accounts receivable from Vinland. We then used the $3.9 million to repay borrowings and interest under our reserve-based credit facility, and for general limited liability company purposes. Under the terms of the private offering, all outstanding units accrued distributions at $1.75 annually from the closing of the private offering to September 30, 2007 and then distributions payable to the Private Investors only increased to $2.40 until the completion of the initial public offering at which time all accrued distributions totaling $5.6 million were paid.

 

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On January 3, 2007, our operating company entered into a reserve-based credit facility. Our initial borrowing base under the reserve-based credit facility was set at $115.5 million. However, the borrowing base was subject to $1 million reductions per month starting on July 1, 2007 through November 1, 2007, which resulted in our current borrowing base of $110.5 million as reaffirmed in November 2007 pursuant to a semi-annual borrowing base redetermination. As of September 30, 2007, our borrowings under the reserve-based credit facility totaled $106.8 million; however, we applied $80 million of our net proceeds from our initial public offering in October 2007 to reduce our indebtedness under our reserve-based credit facility which reduced our outstanding borrowings to $26.8 million. The reserve-based credit facility 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.

 

In November 2007, a sixth amendment to the Credit Facility was executed which set our borrowing base under our reserve-based credit facility at $110.5 million pursuant to our semi-annual redetermination, revised the covenant governing borrowing funds to make distributions, and lowered our borrowing rates. The covenant which prohibited us from making distributions if our borrowings exceeded 80% of our borrowing base was revised to allow us to make distributions if our borrowings were less than 90% of our borrowing base. In addition, the applicable margins on our borrowing base utilization grid were lowered to reflect the following:

 

Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage	<25%	>25% <50%	>50% <75%	>75%
Eurodollar Loans	1.000%	1.250%	1.500%	1.750%
ABR Loans	0.000%	0.250%	0.500%	0.750%
Commitment Fee Rate	0.250%	0.300%	0.375%	0.375%
Letter of Credit Fee	1.000%	1.250%	1.500%	1.750%

 

 

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments, competition from other sources of energy, and access to capital. Natural gas 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 and oil reserves that we can economically produce and our access to capital. As required by our reserve-based credit facility, we have mitigated this volatility for the years 2007 through 2011 by implementing a hedging program on our proved producing and total anticipated production during this time frame.

 

We face the challenge of natural gas production declines. As a given well’s initial reservoir pressures are depleted, natural gas production decreases, thus reducing our total natural gas 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. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability of Vinland to timely obtain drilling permits and regulatory approvals. 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.

 

 

The historical financial statements of our predecessor included in this Quarterly Report on Form 10-Q may not be comparable to our results of operations for the following reasons:

 

·

We conveyed to Vinland 60% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres in the AMI, 100% of our predecessor’s interest in an additional 125,000 undeveloped acres and certain coalbed methane rights located in the Appalachian Basin, the rights to any natural gas and oil located on our acreage at depths above and 100 feet below our known producing horizons and all of our gathering and compression assets. In addition, all of the employees except our President and Chief Executive Officer and Executive Vice-President and Chief Financial Officer were transferred to Vinland.

 

·

We entered into a management services agreement and a gathering and compression agreement with Vinland which will fix a portion of our production costs for wells owned in the AMI.

 

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·

Our predecessor did not account for its derivative instruments as cash flow hedges under SFAS No. 133 until the first quarter of 2007. Accordingly, the changes in the fair value of its derivative instruments were reflected in earnings for all periods prior to 2007 and in Other Comprehensive Income for the nine months ended September 30, 2007.

 

·

We will incur additional selling, general and administrative expense estimated to be $1.9 million per year for costs associated with being a public company. Also, we will incur non-cash compensation charges for the 420,000 Class B units granted to management prior to the completion of the offering, the 40,000 common units to be issued to future employees and/or directors following the completion of this offering, 175,000 options granted to management under our Long-Term Incentive Plan and phantom units to be granted to management commencing in 2008.

 

Results of Operations

 

The following table sets forth selected financial and operating data for the periods ended September 30:

		Three Months Ended September 30,						Nine Months Ended September 30,
		2007			2006			2007			2006
Revenues:
Natural gas and oil sales		$	7,641,064		$	9,574,502		$	26,709,417		$	28,990,485
Realized gains (losses) on derivative contracts			940,566			(161,375	)		(725,286	)		(2,502,849	)
Change in fair value of derivative contracts			-			4,427,600			-			15,851,907
Total revenues			8,581,630		$	13,840,727			25,984,131		$	42,339,543
Costs and expenses:
Lease operating expenses		$	1,347,565		$	1,233,948		$	3,807,985		$	3,608,748
Depreciation, depletion and amortization			2,267,050			2,164,854			6,587,339			6,211,920
Selling, general and administrative expenses			1,084,995			492,958			2,300,484			1,452,856
Bad debt expense			-			-			1,007,458			-
Taxes other than income			326,175			269,975			1,217,167			921,014
Total costs and expenses		$	5,025,785		$	4,161,735		$	14,920,433		$	12,194,538
Other Income and (Expense):
Interest expense, net		$	(2,504,634	)	$	(2,013,307	)	$	(6,896,802	)	$	(5,778,888	)
Loss on extinguishment of debt		$	-		$	-		$	(2,501,528	)	$	-

 

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

 

Revenues

 

Natural gas and oil sales decreased $1.9 million to $7.6 million during the three months ended September 30, 2007 as compared to the same period in 2006. The key revenue measurements were as follows:

		Three Months Ended September 30,						Percentage Increase
		2007			2006			(Decrease)
Net Production:
Total Production (MMcfe)			1,070			1,172			(9	)%
Average Daily production (Mcfe/d)			11,632			12,739			(9	)%
Average Sales Price per Mcfe:
Average realized sales price (including hedges)		$	9.71	(a)	$	7.99			22	%
Average realized sales price (excluding hedges)		$	7.14		$	8.13			(12	)%

 

(a)  Excludes premiums paid on settled derivatives

 

The decrease in natural gas and oil sales was due primarily to the 12% decrease in the average realized sales price received (excluding hedges) coupled with a 9% decrease in the production for the three months ended September 30, 2007 over 2006. The decrease in production can be attributed to our drilling 24 net wells during the first nine months of 2007 as compared to the predecessor drilling 75 net wells in the same period in 2006. Our current business strategy does not envision drilling the same number of net wells as our predecessor and therefore we anticipate having slightly lower levels of production than our predecessor. In addition, results for the three months ended September 30, 2007 were negatively impacted by a $0.7 million prior period adjustment related to measurement discrepancies with a third party pipeline company.

 

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Hedging Activities

 

During the three months ended September 30, 2007, we had hedges in place for approximately 98% of our total production, which resulted in reported revenues that were $0.9 million higher than we would have achieved at unhedged prices. However, the actual cash impact of the hedges increased realizations by an additional $1.8 million for a total of $2.8 million for the three months ended September 30, 2007 after excluding the premiums paid on the settled derivatives. During the three months ended September 30, 2006, we hedged approximately 45% of our total production, which resulted in revenues that were $0.2 million lower than we would have achieved at unhedged prices. The derivative contracts entered into in 2006 were not specifically designated as hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and therefore did not qualify for hedge accounting treatment. As a result, the change in the fair value of these natural gas derivative contracts are marked to market in our earnings each period in 2006 and resulted in a $4.4 million non-cash gain for the three months ended September 30, 2006.

 

Costs and Expenses

 

Production costs consist of the lease operating expenses and taxes other than income taxes (severance and ad valorem taxes). Lease operating expenses includes gathering and compression fees, operating and maintenance costs associated with our gathering systems (which were conveyed to Vinland in connection with the Restructuring) and other customary charges. As a result of the Restructuring, lease operating expenses for the three months ended September 30, 2007 includes third-party transportation costs, a $60 per month per well administrative charge pursuant to a management services agreement with Vinland, a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge for production from wells drilled pre and post January 1, 2007, respectively, paid to Vinland pursuant to a gathering and compression agreement with Vinland, as well as other customary charges. Lease operating expenses increased by $0.1 million to $1.3 million for the three months ended September 30, 2007 as compared to the three months ended September 30, 2006. On a per Mcfe basis, lease operating expenses increased 20% to $1.26 in 2007 as compared to $1.05 in 2006 due principally to increased well tending costs. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state/county and are based on the value of our reserves. Taxes other than income increased slightly for the three months ended September 30, 2007 as compared to the same period in 2006.

 

Depreciation, depletion and amortization increased to approximately $2.3 million for the three months ended September 30, 2007 from approximately $2.2 million for the three months ended September 30, 2006 despite the conveyance of certain assets to Vinland pursuant to the Restructuring effective in January 2007. This result occurred due to the conveyance of long-lived depreciable assets which generated little associated depreciation and the conveyed value of the 60% interest in proved undeveloped properties which was largely offset by the value of new wells drilled since September 30, 2006 and the revisions of future drilling costs in the 2007 reserve report which increased the full cost pool to be depleted.

 

Selling, general and administrative expenses include the costs of our employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. These expenses for the three months ended September 30, 2007 include the impact of the Restructuring which transferred all of the employees other than two of its officers to Vinland. Selling, general and administrative expenses increased $0.6 million during the three months ended September 30, 2007 as compared to the three months ended September 30, 2006. This represents a 120% increase for the three months ended September 30, 2007 over the same period in 2006 primarily resulting from a $0.8 million non-cash compensation charge related to the grant of Class B units to management and employees during 2007. Excluding the impact of the non-cash compensation, selling, general and administrative expenses were $0.3 million for the three months ended September 30, 2007 representing a $0.2 million or 32% decrease from the same period in 2006.

 

Interest and financing expenses were approximately $2.5 million for the three months ended September 30, 2007 compared to approximately $2.0 million for the three months ended September 30, 2006 primarily due to increased debt levels and rising interest rates. In addition, our interest rates during the three months ended September 30, 2007 were directly affected by the provision in our credit facility which increased our rates by 1% on LIBOR loans effective July 1, 2007 until we completed our initial public offering in October 2007.

 

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Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

 

Revenues

 

Natural gas and oil sales decreased to approximately $26.7 million from approximately $29.0 million for the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006. The key revenue measurements were as follows:

 

		Nine Months Ended September 30,									Percentage Increase
			2007						2006			(Decrease)
Net Production:
Total Production (MMcfe)			3,229						3,360			(4	)%
Average Daily production (Mcfe/d)			11,826						12,307			(4	)%
Average Sales Price per Mcfe:
Average realized sales price (including hedges)		$	8.84	(a)				$	7.87			12	%
Average realized sales price (excluding hedges)		$	8.27					$	8.61			(4	)%

 

(a) Excludes premiums paid on settled derivatives.

 

The decrease in natural gas and oil sales was primarily due to the 4% decrease in production coupled with a 4% decrease in the average realized sales price received (excluding hedges) during the nine months ended September 30, 2007 over September 30, 2006. The decrease in production can be attributed to our drilling 24 net wells during the first nine months of 2007 as compared to the predecessor drilling 75 net wells in the same period in 2006. Our current business strategy does not envision drilling the same number of net wells as our predecessor and therefore we anticipate having slightly lower levels of production than our predecessor. In addition, results were negatively impacted by a $0.7 million prior period adjustment recorded in the third quarter of 2007 related to measurement discrepancies with a third party pipeline company.

 

Hedging Activities

 

During the nine months ended September 30, 2007, we hedged approximately 84% of our natural gas production, which resulted in reported revenues that were approximately $0.7 million lower than we would have achieved at unhedged prices. However, the actual cash impact of the hedges increased realizations by $2.5 million for the nine month period after excluding the premiums paid on the settled derivatives. In addition, in January 2007, we terminated existing natural gas swaps at a cost of approximately $2.8 million which resulted in an additional realized loss on derivative contracts of approximately $0.8 million during the nine months ended September 30, 2007. During the nine month ended September 30, 2006, we hedged approximately 51% of our natural gas production, which resulted in revenues that were approximately $2.5 million lower than we would have achieved at unhedged prices. The derivative contracts entered into in 2006 were not specifically designated as hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and therefore did not qualify for hedge accounting treatment. As a result, the change in the fair value of these natural gas derivative contracts are marked to market in our earnings each period in 2006 and resulted in a $15.9 million non-cash gain for the nine months ended September 30, 2006.

 

Costs and Expenses

 

Production costs consist of the lease operating expenses and taxes other than income taxes (severance and ad valorem taxes). Lease operating expenses includes third-party transportation costs, operating and maintenance costs associated with our gathering systems (which were conveyed to Vinland in connection with the Restructuring ) and other customary charges. As a result of the Restructuring, lease operating expenses for the nine months ended September 30, 2007 includes third-party transportation costs, a $60 per month per well administrative charge pursuant to a management services agreement with Vinland, a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge for production from wells drilled pre and post January 1, 2007, respectively, paid to Vinland pursuant to a gathering and compression agreement with Vinland, as well as other customary charges. Lease operating expenses increased only slightly to $3.8 million for the nine months ended September 30, 2007 as compared to $3.6 million for the nine months ended September 30, 2006 due primarily to amounts paid to Vinland under the management services agreement and gathering and compression agreement being comparable to our actual costs incurred for the same period in 2006. On a per Mcfe basis, lease operating expenses increased by10% to $1.18 for the nine months ended September 30, 2007 compared to $1.07 for the same period in 2006. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state and county and are based on the value of our reserves. Taxes other than income increased $0.3 million to $1.2 million or 41% on a per Mcfe basis, for the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006. This increase was principally due to a $0.2 million underaccrual of severance taxes in 2006, which were charged to expense in the first quarter of 2007.

 

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Depreciation, depletion and amortization increased $0.4 million to $6.6 million for the nine months ended September 30, 2007 despite the conveyance of certain assets to Vinland pursuant to the Restructuring effective January 2007. This result occurred due to the conveyance of long-lived depreciable assets which generated little associated depreciation and the conveyed value of the 60% interest in proved undeveloped properties which was largely offset by the value of new wells drilled since September 30, 2006. In addition, the increase in depletion can be attributed to upward revisions of future drilling costs in the 2007 reserve report which increased the full cost pool to be depleted.

 

Selling, general and administrative expenses include the cost of our employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. These expenses for the nine months ended September 30, 2007 include the impact of the Restructuring which transferred all of the employees other than two of its officers to Vinland. Selling, general and administrative expenses increased $0.8 million to $2.3 million for the nine months ended September 30, 2007 as compared to $1.5 million for the nine months ended September 30, 2006. The increase resulted from two principal factors. First, our predecessor capitalized $3.0 million of internal costs under the full cost method of accounting for natural gas and oil properties for the nine months ended September 30, 2006 whereas we have not capitalized any internal costs in 2007. Second, the nine months ended September 30, 2007 includes a $1.3 million non-cash compensation charge related to the grant of Class B units to management and an employee in April and August 2007. Excluding the impact of the approximate $1.3 million non-cash compensation charge discussed above, selling, general and administrative expenses would have been $1.0 million for the nine months ended September 30, 2007 or 32% lower than the comparable 2006 period.

 

Bad debt expense of approximately $1.0 million was recorded during the nine months ended September 30, 2007 as a result of a provision for a loss on the entire amount due from a customer which filed for protection under Chapter 11 of the Bankruptcy Code in May 2007. The account receivable was due from oil sales through December 2006 at which time we ceased selling oil to the customer. As the amount of any potential recovery is uncertain, we elected to reserve the entire balance. We began selling our oil production to a new customer beginning March 2007.

 

Interest and financing expenses were approximately $6.9 million for the nine months ended September 30, 2007 compared to approximately $5.8 million for the nine months ended September 30, 2006. The increase in 2007 is primarily due to increased debt levels associated with drilling additional wells and rising interest rates. In addition, our interest rates during the final three months of the nine months ended September 30, 2007 were directly affected by the provision in our credit facility which increased our rates by 1% on LIBOR loans effective July 1, 2007 until we completed our initial public offering in October 2007.

 

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires management to select and apply accounting policies that best provide the framework to report its results of operations and financial position.  The selection and application of those policies requires management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements.  As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

 

Summary of Significant Accounting Policies

As of September 30, 2007, the Company’s significant accounting policies are consistent with those discussed in Note 1 of the Company’s consolidated financial statements contained in the Company’s Registration Statement on Form S-1 (File No. 333-142363), which is incorporated by reference herein.   

 

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New Accounting Pronouncements Issued But Not Yet Adopted

In September 2006, the financial Accounting Standards Board (“FASB) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 provides guidance for using fair value to measure assets and liabilities and requires additional disclosure about the use of fair value measures, the information used to measure fair value, and the effect fair-value measurements have on earnings. The primary areas in which we utilize fair value measures are valuing derivative financial instruments and asset retirement obligations. SFAS 157 does not require any new fair value measurements. SFAS 157 is effective January 1, 2008. We are in the process of evaluating the impact that SFAS 157 will have on our consolidated financial statements.

 

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (“SFAS 159”), which permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The objective of SFAS 159 is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of SFAS 159 apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. Additional disclosures are also required for instruments for which the fair value option is elected. SFAS 159 is effective for fiscal years beginning after November 15, 2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. The Company is currently evaluating what impact, if adopted, SFAS 159 may have on its results of operations or financial position.

 

Liquidity and Capital Resources

We have utilized private equity, proceeds from bank borrowings, cash flow from operations and, with our recent initial public offering, the public equity markets for capital resources and liquidity.  To date, the primary use of capital has been for the development of natural gas and oil properties; however, as a result of our IPO, we expect to distribute to unitholders a significant portion of our free cash flow.  As we execute our business strategy, we will continually monitor the capital resources available to us to meet future financial obligations, planned capital expenditures, acquisition capital and distributions to our unitholders.  Our future success in growing reserves, production and cash flow will be highly dependent on the capital resources available to us and our success in drilling for or acquiring additional reserves. We expect to fund our maintenance capital expenditures and distributions to unitholders with cash flow from operations, while funding any acquisition capital expenditures that we might incur with borrowings under our reserve-based credit facility and a combination of private and public equity depending on market conditions. Based upon current expectations, we believe existing liquidity and capital resources will be sufficient for the conduct of our business and operations for the foreseeable future.

 

Statements of Cash Flows – Operating Activities

 

At September 30, 2007, we had cash and cash equivalents of approximately $3.2 million compared to $1.7 million at December 31, 2006.

 

Cash provided by operating activities for the nine months ended September 30, 2007 was approximately $2.6 million, compared to cash provided by operating activities of $8.3 million for the nine months ended September 30, 2006.  The decrease in cash provided by operating activities was primarily due to termination of existing natural gas swaps at a cost of approximately $2.8 million, cash paid on early extinguishment of debt of approximately $2.5 million and the payment of $6.5 million for put option derivative contracts during the nine months ended September 30, 2007.

 

Cash flow from operations is subject to many variables, the most significant of which is the volatility of natural gas and oil prices.  Natural gas and oil prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control.  Future cash flow from operations will depend on our ability to maintain and increase production through our drilling program and acquisitions, as well as the prices received for production.  We enter into derivative arrangements to reduce the impact of commodity price volatility on operations.  Currently, we use fixed price swaps and put options to reduce our exposure to the volatility in natural gas and oil prices.  See Note 4 in Notes to Condensed Consolidated Financial Statements for details about derivatives in place through 2011.

 

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Statements of Cash Flows – Investing Activities

Cash used in investing activities was approximately $10.7 million for the nine months ended September 30, 2007, compared to $22.7 million for the nine months ended September 30, 2006.  The decrease in cash used in investing activities was primarily due to a reduction in the number of net wells drilled during 2007 as compared to our predecessor in 2006. As a result of the Restructuring, we only retained 40% of our predecessor’s working interest in undeveloped reserves and thus only incur 40% of what our predecessor would have incurred for the development of new wells. The total for the nine months ended September 30, 2007 includes $9.4 million for the drilling and development of natural gas and oil properties as compared to $17.6 million for the nine months ended September 30, 2006. In addition, the decrease in cash used in investing activities is attributable to the predecessor investing approximately $5.1 million during the nine months ended September 30, 2006 on property and equipment that was conveyed in the Restructuring.

 

 Statements of Cash Flows – Financing Activities

Cash provided by financing activities was approximately $9.5 million for the nine months ended September 30, 2007, compared to $13.9 million for the nine months ended September 30, 2006. During the nine months ended September 30, 2007, total proceeds from borrowings under our reserve-based credit facility were $114.6 million and total payments on this credit facility and our predecessor’s borrowings were $101.9 million.

 

Reserve-Based Credit Facility

On January 3, 2007, our operating company, Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), entered into a reserve-based credit facility under which our initial borrowing base was set at $115.5 million. As of November 15, 2007, our borrowing base was $110.5 million. The reserve-based credit facility 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.

 

As of September 30, 2007, we had $106.8 million outstanding under our reserve-based credit facility.

 

Borrowings under the reserve-based credit facility are available for development, exploitation and acquisition of natural gas and oil properties, working capital and general limited liability company purposes.

 

At our election, interest is determined by reference to:

 

·

the London interbank offered rate, or LIBOR, plus an applicable margin between 1.00% and 1.75% per annum; or

·

a domestic bank rate plus an applicable margin between 0.00% and 0.75% per annum.

 

Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans, but not less frequently than quarterly.

 

The reserve-based credit facility contains various covenants that limit our ability to:

 

·

incur indebtedness;

·

grant certain liens;

·

make certain loans, acquisitions, capital expenditures and investments;

·

make distributions;

·

merge or consolidate; or

·

engage in certain asset dispositions, including a sale of all or substantially all of our assets.

 

The reserve-based credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

 

·

consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0;

·

consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under SFAS No. 133, which includes the current portion of derivative contracts;

 

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·

consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures of not more than 4.0 to 1.0; and

·

maintain unencumbered liquid assets of at least $2 million which includes unused availability under the borrowing base.

 

We have the ability to borrow under the reserve-based credit facility to pay distributions to unitholders as long as there has not been a default or event of default under our reserve-based credit facility and any such distributions for any quarter do not exceed EBITDA (as defined in our credit facility) for such quarter. If our outstanding borrowings equal or exceed 90% of the then-specified borrowing base (or will equal or exceed 90% as a result of a distribution), our reserve-based credit facility restricts our ability to pay distributions. Additionally, outstanding borrowings under our reserve-based credit facility must be reduced to less than 50% of our then-specified borrowing base after any equity offering before making any subsequent distributions.

 

If an event of default exists under the reserve-based credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

 

·

failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

·

a representation or warranty is proven to be incorrect when made;

·

failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

·

default by us on the payment of any other indebtedness in excess of $2.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;

·

bankruptcy or insolvency events involving us or our subsidiaries;

·

the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;

·

specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1.0 million in any year; and

·

a change of control, which includes (1) an acquisition of ownership, directly or indirectly, beneficially or of record, by any person or group (within the meaning of the Securities Exchange Act of 1934 and the rules of the Securities Exchange Commission) of equity interests representing more than 25% of the aggregate ordinary voting power represented by our issued and outstanding equity interests other than by Majeed S. Nami or his affiliates, or (2) the replacement of a majority of our directors by persons not approved by our board of directors.

 

Off-Balance Sheet Arrangements

 

At September 30, 2007, the Company did not have any off-balance sheet arrangements that have, or are reasonably likely to have, a material effect on our financial position or results of operations.

 

Contingencies

 

The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. As of September 30, 2007, there were no loss contingencies.

 

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Commitments and Contractual Obligations

 

A summary of our contractual obligations as of September 30, 2007 is provided in the following table.

 

		Payments Due by Year (in millions)
			2007			2008			2009			2010			2011			After 2011			Total
Management compensation		$	0.1		$	0.6		$	0.6		$	0.1		$	-		$	-		$	1.4
Asset retirement obligations			-			-			-			-			-			0.2			0.2
Derivative liabilities			-			-			-			1.8			1.7			-			3.5
Long-term debt			-			-			-			-			106.8			-			106.8
Total		$	0.1		$	0.6		$	0.6		$	1.9		$	108.5		$	0.2		$	111.9

 

Non-GAAP Financial Measure

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) plus:

•

Net interest expense (including write-off of deferred financing fees);

•

Loss on extinguishment of debt;

•

Depreciation, depletion and amortization (including accretion of asset retirement obligations);

•

Bad debt expenses;

•

Premiums paid on settled derivatives;

•

Change in fair value of derivative contracts;

•                  Non-cash compensation expense; and

•                  Realized (gain) loss on cancelled derivatives.

 

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any cash reserves by our board of directors) the cash distributions we expect to pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

 

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

 

For the three months ended September 30, 2007 as compared to the three months ended September 30, 2006, Adjusted EBITDA increased 13%, from $7.4 million to $8.4 million. For the nine months ended September 30, 2007 as compared to the comparable period of the prior year, Adjusted EBITDA increased 14%, from $20.5 million to $23.3 million.

 

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The following table presents a reconciliation of consolidated net income to adjusted EBITDA:

 

		Vanguard Three Months Ended September 30, 2007					Vanguard Predecessor Three Months Ended September 30, 2006			Vanguard Nine Months Ended September 30, 2007					Vanguard Predecessor Nine Months Ended September 30, 2006
Net income		$	1,051,211				$	7,665,685		$	1,665,368				$	24,366,117
Plus:
Interest expense			2,524,427					2,029,042			6,944,241					5,812,876
Loss on extinguishment of debt			-					-			2,501,528					-
Depreciation, depletion and amortization			2,267,050					2,164,854			6,587,339					6,211,920
Bad debt expense			-					-			1,007,458					-
Premiums paid on settled derivatives			1,813,495					-			2,546,999					-
Change in fair value of derivative contracts(1)			-					(4,427,600	)		-					(15,851,907	)
Non-cash compensation expense			751,635					-			1,314,778					-
Realized loss on cancelled derivatives			-					-			776,634					-
Less:
Interest income			19,793					15,735			47,439					33,988
Adjusted EBITDA		$	8,388,025				$	7,416,246		$	23,296,906				$	20,505,018

 

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(1)

Natural gas derivative contracts were used to reduce our exposure to changes in natural gas prices. They were not specifically designated as hedges under Statement of Financial Accounting Standards (SFAS) No. 133. Change in the fair value of these natural gas derivative contracts are marked to market in our earnings each period. Further, these amounts represent non-cash charges.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

 

Commodity Price Risk

 

Our major market risk exposure is in the pricing applicable to our natural gas production. Realized pricing is primarily driven by the TECO Inside FERC Index Price and the spot market prices applicable to our natural gas production. Pricing for natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside our control.

 

We have entered into and anticipate entering into hedging arrangements with respect to a portion of our projected natural gas production through various transactions that hedge the future prices received. These transactions may include price swaps whereby we will receive a fixed-price for our production and pay a variable market price to the contract counterparty. Additionally, we have put options for which we pay the counterparty the fair value at the purchase date. At the settlement date we receive the excess, if any, of the fixed floor over the floating rate. These hedging activities are intended to support our realized natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.

 

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Interest Rate Risks

At September 30, 2007, we had debt outstanding of $106.8 million, which incurred interest at floating rates based on LIBOR in accordance with our reserve-based credit facility. However, after application of proceeds from our IPO in October 2007, our debt outstanding was reduced to $26.8 million and if the debt remains the same, a 1% increase in LIBOR would result in an estimated $0.3 million increase in annual interest expense.

Item 4.  Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

 

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act as of September 30, 2007, and concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2007.

 

Changes in Internal Control over Financial Reporting

 

There have been no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 Item 3.  Defaults Upon Senior Securities

 

Item 4.  Submission of Matters to a Vote of Security Holders

 

None.

 

Item 5.  Other Information

 

  On November 30, 2007, we issued a press release announcing our results of operations for the three months and nine months ended September 30, 2007. This press release is filed as Exhibit 99.1 to this Quarterly Report on Form 10-Q, and its contents are hereby incorporated by reference into this report.

 

On November 30, 2007, a sixth amendment to the Credit Facility was executed, to be effective November 15, 2007, which set our borrowing base under our Credit Facility at $110.5 million pursuant to our semi-annual redetermination, revised the covenant governing borrowing funds to make distributions, and lowered our borrowing rates. The covenant which prohibited us from making distributions if our borrowings exceeded 80% of our borrowing base was revised to allow us to make distributions if our borrowings were less than 90% of our borrowing base. In addition, the applicable margins on our borrowing base utilization grid were lowered to reflect the following:

 

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Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage	<25%	>25% <50%	>50% <75%	>75%
Eurodollar Loans	1.000%	1.250%	1.500%	1.750%
ABR Loans	0.000%	0.250%	0.500%	0.750%
Commitment Fee Rate	0.250%	0.300%	0.375%	0.375%
Letter of Credit Fee	1.000%	1.250%	1.500%	1.750%

The sixth amendment to the Credit Facility is filed as Exhibit 10.1 to this Quarterly Report on Form 10-Q, and its contents are hereby incorporated by reference into this report.

Item 6.  Exhibits

 

The Exhibit Index is incorporated herein by reference and lists the exhibits required to be filed by this report by Item 601(b)(10)(iii) of Regulation S-K.

 

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SIGNATURE

 

Pursuant to the requirements of the Securities Exchange Act of 1934, Vanguard Natural Resources, LLC has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

	VANGUARD NATURAL RESOURCES, LLC
	(Registrant)
Date: December 6, 2007
	/s/ Richard A. Robert
	Richard A. Robert
	Executive Vice President and
	Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)

 

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Vanguard Natural Resources, LLC

EXHIBIT INDEX

     Each exhibit identified below is filed as a part of this Report.

 

Exhibit
Number	Description
10.1*	Sixth Amendment to Credit Agreement, dated November 15, 2007, by and between Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), Citibank, N.A., as administrative agent and L/C issuer, and the lenders party thereto
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Press release issued on November 30, 2007.
99.2**	Registration Statement on Form S-1 (File No. 333-142363) filed by Vanguard Natural Resources, LLC on April 25, 2007.

 

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*	Filed herewith

**	Incorporated by reference

 

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