NEWS RELEASE
Exhibit 99.1
Vanguard Natural Resources Reports Third Quarter 2010 Results
~Record Adjusted EBITDA of $22.2 million reflecting a 42% increase from Q3 2009~
~ Distributable Cash Flow of $14.5 million~
HOUSTON—November 2, 2010--Vanguard Natural Resources, LLC (NYSE: VNR) ("Vanguard" or "the Company") today reported financial and operational results for the third quarter ended September 30, 2010.
Mr. Scott W. Smith, President and CEO, commented, “This quarter marks another milestone for the company as our production mix is now weighted to greater than 50% of oil and natural gas liquids. The contributions from our oil focused acquisitions are in line with our expectations and we are looking forward to continuing to develop additional oil projects during the balance of the year. From an acquisitions perspective we continue to see a very active market and with the liquidity generated from our recent equity offering we are actively seeking opportunities to continue on our growth track.”
Mr. Richard Robert, Executive Vice President and CFO, added, “Results for the quarter were in-line with our expectations and positions us to meet or exceed the previously provided financial guidance for the full year of 2010.”
Third Quarter 2010 Highlights:
| · | Adjusted EBITDA (a non-GAAP financial measure defined below) increased 42% to $22.2 million from $15.6 million in the third quarter of 2009 and rose 16% from the $19.1 million recorded in the second quarter of 2010. |
| · | Distributable Cash Flow (a non-GAAP financial measure defined below) was increased 12% to $14.5 million from the $13.0 million in the third quarter of 2009 and increased 31% sequentially from the $11.1 million generated in the second quarter of 2010. |
| · | We reported net income for the quarter of $1.9 million or $0.09 per basic unit compared to a reported net income of $0.7 million or $0.05 per basic unit in the third quarter of 2009; however, both quarters included special items. The recent quarter included $10.7 million of unrealized net losses in our commodity and interest rate derivatives contracts, and a $0.06 million non-cash compensation charge for the unrealized fair value of phantom units granted to management. The 2009 third quarter results included $12.8 million in unrealized net losses in our commodity and interest rate derivatives contracts and a $0.8 million non-cash compensation charge for the unrealized fair value of phantom units granted to management. |
| · | Excluding the net impact of the specific non-cash items mentioned above, Adjusted Net Income (a non-GAAP financial measure defined below) was $12.7 million in the third quarter of 2010 or $0.57 per basic unit, as compared to Adjusted Net Income of $8.4 million or $0.58 per basic unit, in the third quarter of 2009. |
| · | Reported average production of 30,455 Mcfe per day, up 49% over 20,396 Mcfe per day produced in the third quarter of 2009 and up 11% over second quarter 2010 average volumes. |
During the quarter we sold 1,289 MMcf of natural gas, 200,289 Bbls of oil, and 2,194,231 gallons of natural gas liquids (NGLs), compared to the 1,266 MMcf of natural gas, 154,445 Bbls of oil and 2,113,571 gallons of natural gas liquids produced in the second quarter of 2010. This 12% increase in total production on a Mcfe basis is primarily due to our recent Parker Creek acquisition. Including the positive impact of our hedges in the third quarter of this year, we realized a net price of $9.56 per Mcf on natural gas sales, $75.46 per Bbl on crude oil sales, and $.99 per gallon on NGL sales, for an average sales price of $10.56 per Mcfe (all excluding amortization of premiums paid and amortization of value on derivative contracts acquired).
2010 Nine-Month Highlights:
| · | Adjusted EBITDA (a non-GAAP financial measure defined below) increased 44% to $59.8 million from the $41.5 million produced in the first nine months of 2009. |
| · | Distributable Cash Flow (a non-GAAP financial measure defined below) grew 19% to $40.7 million from the $34.3 million generated in the comparable period of 2009. |
| · | Net income was $27.5 million for the first nine months of 2010 compared to a net loss of $56.0 million for the first nine months of 2009. The 2010 results included a $5.7 non-cash loss on acquisition of natural gas and oil properties. Last year’s results included a $63.8 million non-cash natural gas and oil property impairment charge, a $16.1 million non-cash unrealized net loss on our commodity and interest rate derivatives contracts and a $3.0 million non-cash compensation charge for the unrealized fair value of phantom units granted to management. |
| · | Excluding the net impact of these specific non-cash items mentioned above, Adjusted Net Income (a non-GAAP financial measure defined below) was $34.0 million in the first nine months of 2010, or $1.66 per unit, compared to Adjusted Net Income of $21.0 million, or $1.59 per unit, in the comparable period of 2009. |
| · | Reported average production of 27,994 Mcfe per day, up 50% over 18,623 Mcfe per day produced in the nine month period of 2009. |
During the nine-months ended we sold 3,764 MMcf of natural gas, 487,145 Bbls of oil, and 6,705,034 gallons of natural gas liquids (NGLs), compared to the 3,288 MMcf of natural gas, 240,748 Bbls of oil and 2,457,649 gallons of natural gas liquids produced in the nine-months ended of 2009. While our natural gas production remained relatively flat, this 50% increase in total production on a Mcfe basis is primarily attributed to our oil production increases from our SUN TSH acquisition last year as well as our recent Parker Creek acquisition. Including the positive impact of our hedges in the nine-months ended of this year, we realized a net price of $9.92 per Mcf on natural gas sales, $76.09 per Bbl on crude oil sales, and $1.06 per gallon on NGL sales, for an average sales price of $10.66 per Mcfe (all excludi ng amortization of premiums paid and amortization of value on derivative contracts acquired).
Recent Events
On August 9, 2010, we announced entering into a 12-month equity distribution agreement with Knight Capital Markets, LLC (KCM), a subsidiary of Knight Capital Group Inc. Under the terms of the agreement, Vanguard retained KCM to act as Vanguard’s exclusive distribution agent with respect to the issuance and sale of Vanguard common units up to an aggregate gross sales price of $60.0 million. Vanguard may from time-to-time propose transactions notices to KCM for the sale of units at an established minimum market price.
During the third quarter 2010, under the equity distribution agreement, we sold 63,826 units at a weighted average price of $25.42 for combined total net proceeds of $1.6 million, after commissions.
In October 2010, we completed an offering of 4.77 million of our common units. The units were offered to the public at a price of $25.40 per unit. We received net proceeds of $112.5 million from the offering, after deducting underwriting discounts of $5.1 million and redeeming 150,000 common units for $3.7 million from our largest unitholder. We used the net proceeds from the offering to repay indebtedness outstanding under our reserve-based credit facility.
Hedging Activities
We enter into derivative transactions in the form of hedging arrangements to reduce the impact of natural gas and oil price volatility on our cash flow from operations. As required by our reserve-based credit facility, we have mitigated this volatility through 2011 for natural gas and through 2014 for crude oil by implementing a hedging program on a portion of our total anticipated production. At September 30, 2010, the fair value of commodity derivative contracts was approximately $20.7 million, of which $21.3 million settles during the next twelve months. Currently, we use fixed-price swaps and NYMEX collars and put options to hedge natural gas and oil prices.
The following table summarizes commodity derivative contracts in place at September 30, 2010:
| October 1, - December 31, 2010 | Year 2011 | Year 2012 | Year 2013 | Year 2014 | ||||||||||||||||
| Gas Positions: | ||||||||||||||||||||
| Fixed Price Swaps: | ||||||||||||||||||||
| Notional Volume (MMBtu) | 1,017,705 | 3,328,312 | — | — | — | |||||||||||||||
| Fixed Price ($/MMBtu) | $ | 10.73 | $ | 7.83 | $ | — | $ | — | $ | — | ||||||||||
| Collars: | ||||||||||||||||||||
| Notional Volume (MMBtu) | 542,800 | 1,933,500 | — | — | — | |||||||||||||||
| Floor Price ($/MMBtu) | $ | 7.67 | $ | 7.34 | $ | — | $ | — | $ | — | ||||||||||
| Ceiling Price ($/MMBtu) | $ | 8.94 | $ | 8.44 | $ | — | $ | — | $ | — | ||||||||||
| Total: | ||||||||||||||||||||
| Notional Volume (MMBtu) | 1,560,505 | 5,261,812 | — | — | — | |||||||||||||||
| Oil Positions: | ||||||||||||||||||||
| Fixed Price Swaps: | ||||||||||||||||||||
| Notional Volume (Bbls) | 90,100 | 443,250 | 347,700 | 296,400 | 209,875 | |||||||||||||||
| Fixed Price ($/Bbl) | $ | 87.17 | $ | 87.94 | $ | 90.03 | $ | 89.84 | $ | 94.37 | ||||||||||
| Collars: | ||||||||||||||||||||
| Notional Volume (Bbls) | 46,000 | — | 45,750 | 45,625 | — | |||||||||||||||
| Floor Price ($/Bbl) | $ | 70.00 | $ | — | $ | 80.00 | $ | 80.00 | $ | — | ||||||||||
| Ceiling Price ($/Bbl) | $ | 80.00 | $ | — | $ | 100.25 | $ | 100.25 | $ | — | ||||||||||
| Total: | ||||||||||||||||||||
| Notional Volume (Bbls) | 136,100 | 443,250 | 393,450 | 342,025 | 209,875 | |||||||||||||||
Calls were sold or options were provided to counterparties to extend the swaps into subsequent years as follows:
| Year 2012 | Year 2013 | Year 2014 | Year 2015 | |||||||||||||
| Swaptions: | ||||||||||||||||
| Notional Volume (Bbls) | 45,750 | 32,100 | 127,750 | 292,000 | ||||||||||||
| Weighted Average Fixed Price ($/Bbl) | $ | 90.40 | $ | 95.00 | $ | 95.00 | $ | 95.63 | ||||||||
Selling, General and Administrative Expense
Our selling, general and administrative expense declined 48% to $1.1 million in the third quarter of 2010 from $2.1 million the same period in 2009, primarily reflecting a $1.1 million decline in the amount of non-cash expenses associated with our unit-based compensation program. The 2009 third quarter charges included a $1.3 million non-cash compensation expense which was related to the grant of phantom units on January 1, 2009 and the amortization of common and Class B units granted to employees and directors under employment agreements and our long-term incentive plan compared to $0.2 million recorded in the current quarter.
Capital Expenditures
Capital expenditures for the drilling, capital workover and recompletion of natural gas and oil wells were approximately $5.6 million for the third quarter of 2010 compared to $1.1 million for the comparable quarter of 2009 and $6.1 million in the second quarter of 2010. The expenditures were as expected and indicative of the continued activity during the third quarter. During the three months ended September 30, 2010, the most significant capital expenditure was the drilling and completion of the Benjamin #8H, a 100% working interest operated horizontal oil well in Third Bone Spring play in Ward County, Texas. The Benjamin #8H was completed on August 26, 2010 with 7 frac stages and averaged 400 boepd for the first 30 days. We have five additional proved undeveloped locations to drill in the Third Bone Spring play.
We anticipate that during the fourth quarter of 2010 our capital expenditures will total approximately $1.5 million which will be primarily spent on the drilling and completing of five vertical oil wells in Appalachia.
Reserve-Based Credit Facility
At September 30, 2010, Vanguard had indebtedness under its reserve-based credit facility totaling $170.9 million with $69.1 million available for borrowing. However, in October 2010, we completed an equity offering with net proceeds of $112.5 million which were used to pay down outstanding borrowings under our reserve-based credit facility. On November 1, 2010, outstanding borrowings totaled $54 million with $186 million available for borrowing before consideration of our fall borrowing base redetermination which is still underway. Our agent bank has made a recommendation to the lenders under the facility that the new borrowing base be set at $225 million. If this borrowing base level is approved by the other lenders in the facility, our availability under the reserve-based credit facility wo uld be reduced to $171 million. Other matters being considered by our lenders include waivers for an over hedged position in natural gas for 2010 and an over hedged position in interest rate derivatives as a result of the recent reduction of outstanding borrowings utilizing the net proceeds of the October common unit offering.
Cash Distributions
On November 12, 2010, the Company will pay a third quarter cash distribution of $0.55 per unit to its unitholders of record as of November 5, 2010. This quarterly distribution payment represents a 10% increase over the third quarter of 2009.
Conference Call Information
Vanguard will host a conference call today to discuss its third quarter results at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial (877) 941-8609 or (480) 629-9818, for international callers and ask for the “Vanguard Natural Resources” call a few minutes prior to the start time. The conference call will also be broadcast live via the Internet and can be accessed through the investor relations section of Vanguard’s website, http://www.vnrllc.com.
A telephonic replay of the conference call will be available through December 2, 2010 and may be accessed by calling (303) 590-3030 and using the pass code 4379639#. A webcast archive will be available on the Investor Relations page at www.vnrllc.com shortly after the call and will be accessible for approximately 30 days. For more information, please contact Lisa Godfrey at (832) 327-2234 or email at investorrelations@vnrllc.com
About Vanguard Natural Resources, LLC
Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition, production and development of natural gas and oil properties. The Company's assets consist primarily of producing and non-producing natural gas and oil reserves located in the southern portion of the Appalachian Basin, the Permian Basin, South Texas and Mississippi. More information on the Company can be found at www.vnrllc.com.
Forward-Looking Statements
We make statements in this news release that are considered forward-looking statements within the meaning of the Securities Exchange Act of 1934. These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this news release are not guarantees of future performance, and we cannot assure you that such stateme nts will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the "Risk Factors" section in our SEC filings and elsewhere in those filings. All forward-looking statements speak only as of the date of this news release. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise.
VANGUARD NATURAL RESOURCES, LLC
Operating Statistics
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | ||||||||||||||||
| Net Natural Gas Production: | |||||||||||||||||||
| Appalachian gas (MMcf) | 762 | 773 | 2,198 | 2,372 | |||||||||||||||
| Permian gas (MMcf) | 100 | 57 | (b) | 279 | 153 | (b) | |||||||||||||
| South Texas gas (MMcf) | 427 | 335 | (a)(c) | 1,287 | (c) | 763 | (a)(c) | ||||||||||||
| Total natural gas production (MMcf) | 1,289 | 1,165 | 3,764 | 3,288 | |||||||||||||||
| Average Appalachian daily gas production (Mcf/day) | 8,276 | 8,403 | 8,050 | 8,691 | |||||||||||||||
| Average Permian daily gas production (Mcf/day) | 1,087 | 617 | (b) | 1,023 | 560 | (b) | |||||||||||||
| Average South Texas daily gas production (Mcf/day) | 4,646 | 3,646 | (a)(c) | 4,715 | (c) | 2,795 | (a)(c) | ||||||||||||
| Average Vanguard daily gas production (Mcf/day) | 14,009 | 12,666 | 13,788 | 12,046 | |||||||||||||||
| Average Natural Gas Sales Price per Mcf: | |||||||||||||||||||
| Net realized gas price, including hedges | $ | 9.56 | (d) | $ | 11.12 | (d) | $ | 9.92 | (d) | $ | 11.13 | (d) | |||||||
| Net realized gas price, excluding hedges | $ | 4.97 | $ | 4.07 | $ | 5.39 | $ | 4.71 | |||||||||||
| Net Oil Production: | |||||||||||||||||||
| Appalachian oil (Bbls) | 27,971 | 25,452 | 89,301 | 63,149 | |||||||||||||||
| Permian oil (Bbls) | 103,327 | 57,525 | (b) | 291,565 | 175,174 | (b) | |||||||||||||
| South Texas oil (Bbls) | 5,341 | 2,425 | (a)(c) | 15,793 | (c) | 2,425 | (a)(c) | ||||||||||||
| Mississippi oil (Bbls) | 63,650 | - | (c) | 90,486 | (c) | - | (c) | ||||||||||||
| Total oil production (Bbls) | 200,289 | 85,402 | 487,145 | 240,748 | |||||||||||||||
| Average Appalachian daily oil production (Bbls/day) | 304 | 277 | 327 | 231 | |||||||||||||||
| Average Permian daily oil production (Bbls/day) | 1,123 | 625 | (b) | 1,068 | 642 | (b) | |||||||||||||
| Average South Texas daily oil production (Bbls/day) | 58 | 26 | (a)(c) | 58 | (c) | 9 | (a)(c) | ||||||||||||
| Average Mississippi daily oil production (Bbls/day) | 692 | - | (c) | 331 | (c) | - | (c) | ||||||||||||
| Average Vanguard daily oil production (Bbls/day) | 2,177 | 928 | 1,784 | 882 | |||||||||||||||
| Average Oil Sales Price per Bbl: | |||||||||||||||||||
| Net realized oil price, including hedges | $ | 75.46 | (d) | $ | 77.15 | (d) | $ | 76.09 | (d) | $ | 74.64 | (d) | |||||||
| Net realized oil price, excluding hedges | $ | 70.48 | $ | 63.76 | $ | 71.44 | $ | 52.42 | |||||||||||
| Net Natural Gas Liquids Production: | |||||||||||||||||||
| Permian natural gas liquids (Gal) | 397,572 | 105,336 | (b) | 1,082,037 | 340,536 | (b) | |||||||||||||
| South Texas natural gas liquids (Gal) | 1,796,659 | 1,285,876 | (a) | 5,622,997 | 2,117,113 | (a) | |||||||||||||
| Total natural gas liquids production (Gal) | 2,194,231 | 1,391,212 | 6,705,034 | 2,457,649 | |||||||||||||||
| Average Permian daily natural gas liquids production (Gal/day) | 4,321 | 1,145 | (b) | 3,963 | 1,247 | (b) | |||||||||||||
| Average South Texas daily natural gas liquids production (Gal/day) | 19,529 | 13,977 | (a) | 20,597 | 7,755 | (a) | |||||||||||||
| Average Vanguard daily natural gas liquids production (Gal/day) | 23,850 | 15,122 | 24,560 | 9,002 | |||||||||||||||
| Average Natural Gas Liquids Sales Price per Gal | $ | 0.99 | $ | 0.82 | $ | 1.06 | $ | 0.74 | |||||||||||
| (a) | 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 or nine month periods ended September 30, 2009. |
| (b) | The Ward County acquisition closed on December 2, 2009 and, as such, no operations are included in the three or nine month periods ended September 30, 2009. |
| (c) | South Texas area includes production from the Dos Hermanos, Sun TSH and Parker Creek acquisitions. The Parker Creek acquisition closed on May 20, 2010 and, as such, only four months and eleven days of operations are included in the nine month period ended September 30, 2010, and no operations are included in the three or nine month periods ended September 30, 2009. The average daily production above is calculated based on the total number of days in the reported period regardless of how many days an acquisition contributed production in the reported period. The average daily production for the South Texas area, calculated using the actual number of days for the Parker Creek acquisition from the closing date to the end of the reported period, was 4,798 Mcf/day of natural gas and 69 Bbls/day of oil for the nine months ended September 30, 2010. The avera ge daily production for the Mississippi area, calculated using the actual number of days for the Parker Creek acquisition from the closing date to the end of the reported period, was 26 Mcf/day of natural gas and 591Bbls/day of oil for both the nine month period ended September 30, 2010. |
| (d) | Excludes amortization of premiums paid and amortization of value on derivative contracts acquired. |
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
| 2010 | 2009(a)(b) | 2010 (c) | 2009 (a)(b) | ||||||||||
| Revenues: | |||||||||||||
| Natural gas, natural gas liquids and oil sales | $ | 22,684 | $ | 11,324 | $ | 62,200 | $ | 29,930 | |||||
| Loss on commodity cash flow hedges | (568 | ) | (463 | ) | (2,127 | ) | (1,737 | ) | |||||
| Realized gain on other commodity derivative contracts | 6,513 | 8,010 | 18,274 | 23,794 | |||||||||
| Unrealized gain (loss) on other commodity derivative contracts | (9,388 | ) | (12,220 | ) | 1,332 | (16,492 | ) | ||||||
| Total revenues | 19,241 | 6,651 | 79,679 | 35,495 | |||||||||
| Costs and expenses: | |||||||||||||
| Lease operating expenses | 4,838 | 3,322 | 13,545 | 9,233 | |||||||||
| Depreciation, depletion, amortization, and accretion | 6,179 | 3,272 | 16,130 | 9,700 | |||||||||
| Impairment of natural gas and oil properties | — | — | — | 63,818 | |||||||||
| Selling, general and administrative expenses | 1,104 | 2,137 | 3,638 | 8,230 | |||||||||
| Production and other taxes | 1,753 | 974 | 5,215 | 2,537 | |||||||||
| Total costs and expenses | 13,874 | 9,705 | 38,528 | 93,518 | |||||||||
| Income (loss) from operations | 5,367 | (3,054 | ) | 41,151 | (58,023 | ) | |||||||
| Other income and (expense): | |||||||||||||
| Interest expense | (1,708 | ) | (1,042 | ) | (4,522 | ) | (3,034 | ) | |||||
| Realized loss on interest rate derivative contracts | (410 | ) | (506 | ) | (1,408 | ) | (1,240 | ) | |||||
| Unrealized gain (loss) on interest rate derivative contracts | (1,337 | ) | (575 | ) | (2,021 | ) | 387 | ||||||
| Loss on acquisition of natural gas and oil properties | — | 5,878 | (5,680 | ) | 5,878 | ||||||||
| Total other income (expense) | (3,455 | ) | 3,755 | (13,631 | ) | 1,991 | |||||||
| Net income (loss) | $ | 1,912 | $ | 701 | $ | 27,520 | $ | (56,032 | ) | ||||
| Net income (loss) per unit: | |||||||||||||
| Common & Class B units – basic | $ | 0.09 | $ | 0.05 | $ | 1.35 | $ | (4.24 | ) | ||||
| Common & Class B units – diluted | $ | 0.09 | $ | 0.05 | $ | 1.34 | $ | (4.24 | ) | ||||
| Weighted average units outstanding: | |||||||||||||
| Common units – basic | 21,671 | 14,027 | 20,037 | 12,780 | |||||||||
| Common units –diluted | 21,710 | 14,027 | 20,071 | 12,780 | |||||||||
| Class B units – basic & diluted | 420 | 420 | 420 | 420 | |||||||||
| (a) | 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 or nine month periods ended September 30, 2009. |
| (b) | The Ward County acquisition closed on December 2, 2009 and, as such, no operations are included in the three or nine month periods ended September 30, 2009. |
| (c) | The Parker Creek acquisition closed on May 20, 2010 and, as such, only four months and eleven days of operations are included in the nine month periods ended September 30, 2010. |
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
September 30, 2010 | December 31, 2009 | |||||||
| (Unaudited) | ||||||||
| Assets | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | 3,234 | $ | 487 | ||||
| Trade accounts receivable, net | 9,249 | 8,025 | ||||||
| Derivative assets | 21,332 | 16,190 | ||||||
| Other receivables | 1,870 | 2,224 | ||||||
| Other current assets | 1,127 | 1,317 | ||||||
| Total current assets | 36,812 | 28,243 | ||||||
| Natural gas and oil properties, at cost | 522,272 | 399,212 | ||||||
| Accumulated depletion | (242,630 | ) | (226,687 | ) | ||||
| Natural gas and oil properties evaluated, net – full cost method | 279,642 | 172,525 | ||||||
| Other assets | ||||||||
| Derivative assets | 1,198 | 5,225 | ||||||
| Deferred financing costs | 3,110 | 3,298 | ||||||
| Other assets | 1,227 | 1,409 | ||||||
| Total assets | $ | 321,989 | $ | 210,700 | ||||
| Liabilities and members’ equity | ||||||||
| Current liabilities | ||||||||
| Accounts payable – trade | $ | 1,086 | $ | 766 | ||||
| Accounts payable – natural gas and oil | 2,542 | 2,299 | ||||||
| Payables to affiliates | 1,100 | 1,387 | ||||||
| Deferred swap premium liability | 1,643 | 1,334 | ||||||
| Derivative liabilities | 340 | 253 | ||||||
| Phantom unit compensation accrual | 103 | 4,299 | ||||||
| Accrued ad valorem tax | 1,756 | 903 | ||||||
| Accrued expenses | 768 | 1,178 | ||||||
| Total current liabilities | 9,338 | 12,419 | ||||||
| Long-term debt | 170,900 | 129,800 | ||||||
| Derivative liabilities | 5,759 | 2,036 | ||||||
| Deferred swap premium liability | 432 | 1,739 | ||||||
| Asset retirement obligations | 5,160 | 4,420 | ||||||
| Total liabilities | 191,589 | 150,414 | ||||||
| Commitments and contingencies | ||||||||
| Members’ equity | ||||||||
| Members’ capital, 21,729,999 common units issued and outstanding at September 30, 2010 and 18,416,173 at December 31, 2009 | 128,609 | 59,873 | ||||||
| Class B units, 420,000 issued and outstanding at September 30, 2010 and December 31, 2009 | 5,397 | 5,930 | ||||||
| Accumulated other comprehensive loss | (3,606 | ) | (5,517 | ) | ||||
| Total members’ equity | 130,400 | 60,286 | ||||||
| Total liabilities and members’ equity | $ | 321,989 | $ | 210,700 | ||||
Use of Non-GAAP Measures
Adjusted EBITDA
We present Adjusted EBITDA in addition to our reported net income (loss) in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) plus:
| · | Net interest expense, including write-off of deferred financing fees and realized gains and losses on interest rate derivative contracts; |
| · | Depreciation, depletion and amortization (including accretion of asset retirement obligations); |
| · | Impairment of natural gas and oil properties; |
| · | Amortization of premiums paid on derivative contracts; |
| · | Amortization of value on derivative contracts acquired; |
| · | Unrealized gains and losses on other commodity and interest rate derivative contracts; |
| · | Gains and losses on acquisitions of natural gas and oil properties; |
| · | Deferred taxes, and |
| · | Unit-based compensation expense. |
Adjusted EBITDA is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors, debt service and capital expenditures) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating pe rformance and return on capital as compared to those of other companies in our industry. Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.
Distributable Cash Flow
We present Distributable Cash Flow in addition to our reported net income (loss) in accordance with GAAP. Distributable Cash Flow is a non-GAAP financial measure that is defined as net income (loss) plus:
| · | Depreciation, depletion and amortization (including accretion of asset retirement obligations); |
| · | Impairment of natural gas and oil properties; |
| · | Amortization of premiums paid on derivative contracts; |
| · | Amortization of value on derivative contracts acquired; |
| · | Unrealized gains and losses on other commodity and interest rate derivative contracts; |
| · | Gains and losses on acquisitions of natural gas and oil properties; |
| · | Deferred taxes, and |
| · | Unit-based compensation expense. |
| Less: |
| · | Drilling, capital workover and recompletion expenditures. |
Distributable Cash Flow is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. While Distributable Cash Flow is measured on a quarterly basis for reporting purposes, management must consider the timing and size of its planned capital expenditures in determining the sustainability of its quarterly distribution. Capital expenditures are typically not spent evenly throughout the year due to a variety of factors including weather, rig availability, and the commodity price environment. As a result, there will be some volatility in Distributable Cash Flow measured on a quarterly basis. Distributable Cash Flow is not intended to be a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) to Adjusted EBITDA (a) and Distributable Cash Flow
(Unaudited)
(in thousands)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 (b)(c) | 2010 (d) | 2009 (b)(c) | |||||||||||||
| Net income (loss) | $ | 1,912 | $ | 701 | $ | 27,520 | $ | (56,032 | ) | |||||||
| Plus: | ||||||||||||||||
| Interest expense, including realized losses on interest rate derivative contracts | 2,118 | 1,548 | 5,930 | 4,274 | ||||||||||||
| Depreciation, depletion, amortization, and accretion | 6,179 | 3,272 | 16,130 | 9,700 | ||||||||||||
| Impairment of natural gas and oil properties | - | - | - | 63,818 | ||||||||||||
| Amortization of premiums paid on derivative contracts | 481 | 858 | 1,479 | 2,676 | ||||||||||||
| Amortization of value on derivative contracts acquired | 489 | 953 | 1,657 | 1,707 | ||||||||||||
| Unrealized losses on other commodity and interest rate derivative contracts | 10,725 | 12,795 | 689 | 16,105 | ||||||||||||
| (Gain) loss on acquisition of natural gas and oil properties | - | (5,878 | ) | 5,680 | (5,878 | ) | ||||||||||
| Deferred taxes | 12 | (3 | ) | (37 | ) | (204 | ) | |||||||||
| Unit-based compensation expense | 190 | 548 | 656 | 2,311 | ||||||||||||
| Unrealized fair value of phantom units granted to officers | 55 | 782 | 103 | 3,034 | ||||||||||||
| Adjusted EBITDA | $ | 22,161 | $ | 15,576 | $ | 59,807 | $ | 41,511 | ||||||||
| Less: | ||||||||||||||||
| Interest expense | 2,118 | 1,548 | 5,930 | 4,274 | ||||||||||||
| Drilling, capital workover and recompletion expenditures | 5,572 | 1,069 | 13,220 | 2,981 | ||||||||||||
| Distributable Cash Flow | $ | 14,471 | $ | 12,959 | $ | 40,657 | �� | $ | 34,256 | |||||||
| (a) | Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. |
| (b) | 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 or nine month periods ended September 30, 2009. |
| (c) | The Ward County acquisition closed on December 2, 2009 and, as such, no operations are included in the three or nine month periods ended September 30, 2009. |
| (d) | The Parker Creek acquisition closed on May 20, 2010 and, as such, only four months and eleven days of operations are included in the nine month periods ended September 30, 2010. |
Adjusted Net Income
We present Adjusted Net Income in addition to our reported net income in accordance with GAAP. Adjusted Net Income is a non-GAAP financial measure that is defined as net income (loss) plus:
| · | Unrealized gains and losses on other commodity derivative contracts; |
| · | Unrealized gains and losses on interest rate derivative contracts; |
| · | Unrealized fair value of phantom units granted to management; |
| · | Impairment of natural gas and oil properties; and |
| · | Gains and losses on acquisitions of natural gas and oil properties. |
This information is provided because management believes exclusion of the impact of our unrealized derivatives not accounted for as cash flow hedges, non-cash gains and losses on acquisitions of natural gas and oil properties and non-cash natural gas and oil property impairment charge will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the impact that commodity price volatility has on our results. Adjusted Net Income is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) to Adjusted Net Income
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
| Net income (loss) | $ | 1,912 | $ | 701 | $ | 27,520 | $ | (56,032 | ) | |||||||
| Plus: | ||||||||||||||||
| Unrealized (gain) loss on other commodity derivative contracts | 9,388 | 12,220 | (1,332 | ) | 16,492 | |||||||||||
| Unrealized (gain) loss on interest rate derivative contracts | 1,337 | 575 | 2,021 | (387 | ) | |||||||||||
| Unrealized fair value of phantom units granted to officers | 55 | 782 | 103 | 3,034 | ||||||||||||
| Impairment of natural gas and oil properties | - | - | - | 63,818 | ||||||||||||
| (Gain) loss on acquisition of natural gas and oil properties | - | (5,878 | ) | 5,680 | (5,878 | ) | ||||||||||
| Total adjustments | 10,780 | 7,699 | 6,472 | 77,079 | ||||||||||||
| Adjusted Net Income | $ | 12,692 | $ | 8,400 | $ | 33,992 | $ | 21,047 | ||||||||
| Basic net income (loss) per unit: | $ | 0.09 | $ | 0.05 | $ | 1.35 | $ | (4.24 | ) | |||||||
| Plus: | ||||||||||||||||
| Unrealized (gain) loss on other commodity derivative contracts | 0.42 | 0.85 | (0.07 | ) | 1.25 | |||||||||||
Unrealized (gain) loss on interest rate derivative contracts | 0.06 | 0.04 | 0.10 | (0.03 | ) | |||||||||||
| Unrealized fair value of phantom units granted to officers | - | 0.05 | - | 0.23 | ||||||||||||
Impairment of natural gas and oil properties | - | - | - | 4.83 | ||||||||||||
| Loss on acquisition of natural gas and oil properties | - | (0.41 | ) | 0.28 | (0.45 | ) | ||||||||||
Basic adjusted net income per unit: | $ | 0.57 | $ | 0.58 | $ | 1.66 | $ | 1.59 | ||||||||
Vanguard Natural Resources, LLC
Lisa Godfrey, 832-327-2234
investorrelations@vnrllc.com