Vanguard Natural Resources Reports Record Adjusted EBITDA, Production and Proved Reserves for 2009 and Provides Positive Outlook on 2010
HOUSTON, March 3 /PRNewswire-FirstCall/ -- Vanguard Natural Resources, LLC (NYSE: VNR) ("Vanguard" or "the Company") today reported financial and operational results for the full year and fourth quarter ended December 31, 2009 and provided financial and operational guidance for 2010.
Mr. Scott W. Smith, President and CEO, commented, "In the face of a very challenging environment for the domestic oil and gas sector and the overall economy, Vanguard achieved excellent results on behalf of its unitholders in 2009. During the year we successfully closed two accretive acquisitions in our core operating areas, both of which were funded primarily with proceeds from equity offerings. With these acquisitions in place, we were pleased to announce in January 2010 the 5% increase in our quarterly distribution to $0.525 or $2.10 on an annual basis. Looking forward, we feel well positioned to continue the growth we saw last year as we currently have ample liquidity on our credit facility and access to the capital markets to help fund the acquisition opportunities we believe will be available during the year."
Full Year 2009 Highlights:
- Achieved Adjusted EBITDA (a non-GAAP financial measure defined below) of $56.2 million, up 15% over $48.8 million in 2008.
- Generated Distributable Cash Flow (a non-GAAP financial measure defined below) of $45.1 million, representing an 80% increase over the $25 million generated in 2008.
- Reported average daily production of 20,010 thousand cubic feet equivalent ("Mcfe") per day, up 23% over the average of 16,206 Mcfe/day reported in 2008.
- Proved reserves increased by 32% to 142.9 billion cubic feet equivalent (Bcfe). The additions to proved reserves in 2009 totaled 41.7 Bcfe (including purchases, extensions and revisions), replacing 571% of production.
- Reported a net loss of $95.7 million for 2009, which included a non-cash natural gas and oil property impairment charge of $110.2 million and included non-cash unrealized net losses from our commodity and interest rate derivative contracts of $18.3 million. Excluding the impact of these charges and other non-cash adjustments which have no impact on our ability to make our cash distributions, our Adjusted Net Income (a non-GAAP financial measure defined below) was $26.1 million in 2009 compared to $19.3 million in 2008.
- Recognized as the best performing master limited partnership in terms of unit appreciation for 2009 at 274%.
Fourth Quarter 2009 Highlights:
- Generated Adjusted EBITDA (a non-GAAP financial measure defined below) of $14.7 million, up 17% over $12.6 million in the fourth quarter of 2008 but down 6% over third quarter 2009.
- Generated Distributable Cash Flow (a non-GAAP financial measure defined below) of $10.8 million, representing an 80% increase over the $6.0 million generated in the fourth quarter of 2008.
- Reported average production of 24,125 Mcfe/day, up 30% over 18,576 Mcfe/day produced in the fourth quarter of 2008 and up 18% over third quarter 2009 average volumes.
- Exited 2009 with average production at 25,768 Mcfe/day
- Recorded a net loss of $39.7 million compared to net loss of approximately $12.6 million in the 2008 fourth quarter. The recent quarter included a non-cash natural gas and oil property impairment charge of $46.3 million under our full-cost accounting method and included non-cash unrealized net losses from our commodity and interest rate derivative contracts of $2.2 million. Excluding the impact of these charges and other non-cash adjustments which have no impact on our ability to make our cash distributions, our Adjusted Net Income was $5.1 million in the fourth quarter of 2009 as compared to Adjusted Net Income of $4.0 million in the fourth quarter of 2008.
Year-End 2009 Proved Reserves
As provided by our outside reserve engineering firms, Vanguard's year-end 2009 proved reserves consist of 142.9 Bcfe, 32% more than the 2008 year-end reserves of 108.5 Bcfe. Of these proven reserves, 68% are proved developed. During 2009, Vanguard replaced 571% of its production, primarily with reserves added through acquisitions. Vanguard added 74.7 Bcfe through acquisitions and 3.6 Bcfe through other reserve adds, while price revisions, performance revisions and production reduced proved reserves by 43.9 Bcfe. Vanguard's proved reserves are 58% natural gas, 27% crude oil and 15% natural gas liquids.
For year-end 2009, new Securities and Exchange Commission (SEC) rules require that the value of proved reserves be based on the unweighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period (the "12-month average price") rather than the previous method which required the reserve calculation to be computed using end-of-period spot prices (both methods holding pricing constant). The 12-month average price for natural gas and oil is $3.87 per million British thermal units (MMBtu) and $61.04 per barrel of crude oil, compared to year-end 2009 spot prices of $5.79 per MMBtu and $79.39 per barrel of crude oil. The SEC's new pricing requirements negatively affected the volume of reportable proved reserves and the estimated future net cash flows from the proved reserves as there were lower natural gas and oil prices during the first half of 2009. The Company believes a reserve valuation which incorporates forward market pricing over the long term better reflects the current value of its proved reserves when compared to valuations arrived at using a constant pricing model.
The following table compares Vanguard's year-end proved reserves, estimated future net cash flows from proved reserves discounted at an annual rate of 10% (PV-10) based on the 2009 twelve month average price required by the new SEC rules, spot prices at year-end 2009 and the NYMEX strip pricing through 2021 as of December 31, 2009:
Price Assumption Proved Reserves, Bcfe PV-10, $Million
---------------- ---------------------- ---------------
SEC 2009 12-Month Average Price –
As Reported 143 $179
End of Year Spot Price -
December 31, 2009 157 $331
12 Year NYMEX Strip Pricing as of
December 31, 2009 165 $454
Impairment Charge
We utilize the full cost method of accounting for our natural gas and oil properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of natural gas, natural gas liquids and oil reserves are capitalized and are subject to amortization and ceiling test limitations. Prior to December 31, 2009, the ceiling was based on the net present value of our estimated future revenues, as determined by the commodity spot prices at the end of each quarter, discounted at 10%. At December 31, 2009, as a result of the SEC's Final Rule, "Modernization of Oil and Gas Reporting," which became effective December 31, 2009, we changed the price used to calculate the value of our natural gas and oil reserves to a 12-month average price rather than a year-end price. Our capitalized costs must be equal to or less than this ceiling.
We recorded a non-cash ceiling test impairment of natural gas and oil properties for the year ended December 31, 2009 of $110.2 million. The impairment for the first quarter 2009 was $63.8 million as a result of a decline in natural gas and oil prices at the measurement date, March 31, 2009. This impairment was calculated based on prices of $3.65 per MMBtu for natural gas and $49.64 per barrel of crude oil.
As a result of declines in natural gas and oil prices during the first half of 2009 and the SEC's new rule requiring the use of a 12-month average price, we recorded an additional impairment of $46.4 million in the fourth quarter of 2009. This impairment was calculated using the 12-month NYMEX average price of $3.87 per MMBtu for natural gas and $61.04 per barrel for crude oil. The majority of the fourth quarter impairment was incurred on properties that we acquired in the last six months of 2009 when natural gas and oil prices were higher than the 12-month average price. We were able to lock in the higher prices at the time of the acquisitions for a substantial portion of the expected production through 2011 for natural gas and 2013 for crude oil by using commodity derivative contracts. However, the impairment calculation did not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allows the inclusion of derivatives designated as cash flow hedges.
Selling, General and Administrative Expense
Our selling, general and administrative expense rose 59% to $10.6 million for the year ending December 31, 2009 as compared to $6.7 million in 2008. The increase is attributable to the payments made under the phantom unit bonus plan discussed below.
In accordance with their previously negotiated employment agreements, at the beginning of each year, phantom units were granted to two officers in amounts equal to 1% of our units outstanding at January 1 and the amount paid in either cash or units equalled the appreciation in value of the units, if any, from the date of the grant until the determination date (end of the applicable year), plus cash distributions paid on the units, less an 8% hurdle rate. No amounts were paid under this plan in 2008. As a result of the Company's unit price increasing 274% during 2009 (from $5.90 to $22.07) and the Company paying a $2.00 distribution in 2009 the fair value of the phantom units at December 31, 2009 was $4.3 million.
The estimated phantom unit expense was recorded each quarter over the course of 2009 based on a Black Sholes model until the actual $4.3 million amount could be calculated using the year-end 2009 unit price. However, as the amount was only an estimate until year-end, the phantom unit expense was added back to Adjusted EBITDA in each of the first three quarters of 2009 and the entire expense was reflected as a negative adjustment in the calculation of fourth quarter 2009 Adjusted EBITDA. The two officers elected to take a portion of their phantom unit compensation in cash and a portion in the Company's units. The Company satisfied the unit portion of the compensation by transferring units it had purchased in the open market at various times throughout the year at a weighted average price below the year-end closing price of $22.07. As a result, the actual cash expense as reflected in Adjusted EBITDA to satisfy the $4.3 million obligation was reduced to $3.9 million. Excluding the impact of this non-recurring item, our Adjusted EBITDA would have been $60.1 million and $18.6 million for the year and fourth quarter ended December 31, 2009, respectively.
As more fully described in our 8-K filing made on February 8, 2010, new three year employment agreements have been entered into with the two officers. The new agreements include a revised annual bonus structure which includes two company performance elements and a third discretionary element to be determined by the Company's board of directors. The annual bonus does not require a minimum payout and the maximum payout may not exceed two times the respective officer's annual base salary.
Hedging Activities
We enter into derivative transactions in the form of hedging arrangements to reduce the impact of natural gas and oil price volatility on our cash flow from operations. As required by our reserve-based credit facility, we have mitigated this volatility through 2011 for our natural gas production and 2013 for our crude oil production by implementing a hedging program on a portion of our total anticipated production. Currently, we use fixed-price swaps and NYMEX collars to hedge natural gas and oil prices.
The following table summarizes commodity derivative contracts in place at December 31, 2009:
2010 2011 2012 2013
---- ---- ---- ----
Gas Positions:
Fixed Price Swaps:
Notional Volume (MMBtu) 4,731,040 3,328,312 - -
Weighted Average Fixed Price
($/MMBtu) $8.66 $7.83 $- $-
Collars:
Notional Volume (MMBtu) 1,607,500 1,933,500 - -
Floor Price ($/MMBtu) $7.73 $7.34 $- $-
Ceiling Price ($/MMBtu) $8.92 $8.44 $- $-
Total:
Notional Volume (MMBtu) 6,338,540 5,261,812 - -
Oil Positions:
Fixed Price Swaps:
Notional Volume (Bbls) 310,250 260,750 137,250 118,625
Weighted Average Fixed Price
($/Bbl) $85.93 $86.12 $88.13 $88.42
Collars:
Notional Volume (Bbls) - - 45,750 45,625
Floor Price ($/Bbl) $- $- $80.00 $80.00
Ceiling Price ($/Bbl) $- $- $100.25 $100.25
Total:
Notional Volume (Bbls) 310,250 260,750 183,000 164,250
Based on our current drilling plans, approximately 89% of our 2010 natural gas production (including natural gas liquids) is hedged at a weighted average floor price of $8.42 per MMBtu. Approximately 60% of our 2010 crude oil production is hedged at a weighted average floor price of $85.93 per barrel.
Cash Distributions
On February 12, 2010, the Company paid its 2009 fourth-quarter cash distribution of $0.525 per unit to its unit holders of record. This quarterly distribution payment was an increase of $0.025 per unit over the amount distributed for the third quarter of 2009 and represented an increase of $0.100 per unit, or 24%, over the $0.425 distribution initially set when our initial public offering was completed on October 29, 2007.
Capital Expenditures
Our capital expenditures were $109.3 million in the year ended December 31, 2009 compared to $119.5 million for the year ended December 31, 2008. The expenditures included $103.9 million and $100.7 million in 2009 and 2008, respectively, for the acquisition of natural gas and oil properties in the Permian Basin and South Texas. It also included $5.0 million for the drilling and development of natural gas and oil properties as compared to $18.2 million for the year ended December 31, 2008. We currently anticipate a capital budget for 2010 of between $12.5 million and $13.5 million, which consists of a new well drilling program and recompletions and workovers of existing wells. All capital expenditures are expected to be funded through cash from operations.
Reserve-based Credit Facility
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. In December 2009, our borrowing base was increased to $195.0 million pursuant to an interim redetermination requested by the Company due to the Ward County acquisition. As of December 31, 2009, our indebtedness under the reserve-based credit facility totaled $129.8 million. On March 3, 2010, we had $57.3 million available for borrowing under our reserve-based credit facility.
Conference Call Information
Vanguard will host a conference call today to discuss its 2009 full year and fourth quarter results and 2010 outlook on Wednesday, March 3rd, 2010 at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial (877) 941-2930 or (480) 629-9690 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 corporate website, http://www.vnrllc.com.
A telephonic replay of the conference call will be available until March 16, 2010 and may be accessed by calling (303) 590-3030 and using the pass code 4246688#. 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 [email protected].
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, and south Texas. 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 statements 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 Year Ended
December 31, December 31,
2009 2008 2009 2008
---- ---- ---- ----
Net Natural Gas
Production:
Appalachian gas
(MMcf) 731 885 3,103 3,578
Permian gas (MMcf) 72 (a) 53 225 (a) 185 (b)
South Texas gas
(MMcf) 451 249 1,214 (c) 428 (d)
--- --- ----- ---
Total natural gas
production (MMcf) 1,254 1,187 4,542 4,191
----- ----- ----- -----
Average Appalachian
daily gas
production
(Mcf/ day) 7,944 9,628 8,502 9,777
Average Permian
daily gas
production
(Mcf/ day) 783 (a) 576 616 (a) 505 (b)
Average South Texas
daily gas
production
(Mcf/ day) 4,902 2,700 3,326 (c) 1,168 (d)
----- ----- ----- -----
Average Vanguard
daily gas
production
(Mcf/ day) 13,629 12,904 12,444 11,450
------ ------ ------ ------
Average Natural Gas
Sales Price per Mcf:
Net realized gas
price, including
hedges $11.21 (e) $9.73 (e) $11.15 (e) $10.49 (e)
Net realized gas
price, excluding
hedges $5.16 $7.32 4.84 $10.38
Net Oil Production:
Appalachian oil
(Bbls) 30,565 16,434 93,713 48,977
Permian oil (Bbls) 67,126 (a) 55,136 242,301 (a) 212,599 (b)
South Texas oil
(Bbls) 6,961 - 9,386 (c) -
----- --- ----- ---
Total oil production
(Bbls) 104,652 71,570 345,400 261,576
------- ------ ------- -------
Average Appalachian
daily oil
production
(Bbls/ day) 332 179 257 134
Average Permian
daily oil
production
(Bbls/ day) 729 (a) 599 664 (a) 581 (b)
Average South
Texas daily oil
production
(Bbls/ day) 76 - 26 (c) -
--- --- --- ---
Average Vanguard
daily oil
production
(Bbls/ day) 1,137 778 947 715
----- --- --- ---
Average Oil Sales
Price per Bbl:
Net realized oil
price, including
hedges $79.69 (e) $80.57 (e) $75.26 (e) $85.69 (e)
Net realized oil
price, excluding
hedges $69.95 $54.11 $57.73 $91.48
Net Natural Gas
Liquids
Production:
Permian natural
gas liquids
(Gal) 114,404 (a) 103,109 454,940 (a) 231,280 (b)
South Texas
natural gas
liquids (Gal) 2,248,901 544,038 4,366,016 (c) 965,718 (d)
--------- ------- --------- -------
Total natural
gas liquids
production (Gal) 2,363,305 647,147 4,820,956 1,196,998
--------- ------- --------- ---------
Average Permian
daily natural
gas liquids
production
(Gal/ day) 1,243 (a) 1,121 1,247 (a) 632 (b)
Average South
Texas daily
natural gas
liquids
production
(Gal/ day) 24,444 5,913 11,961 (c) 2,639 (d)
------ ----- ------ -----
Average Vanguard
daily natural
gas liquids
production
(Gal/ day) 25,687 7,034 13,208 3,271
------ ----- ------ -----
Average Natural
Gas Liquids Sales
Price per Gal:
Net realized
natural gas
liquids price,
including hedges $0.98 (e) $0.92 (e) $0.86 (e) $1.18 (e)
Net realized
natural gas
liquids price,
excluding
hedges $0.98 $0.92 $0.86 $1.18
(a) Includes production from the Permian Basin and Ward County
acquisitions. The Ward County acquisition closed on December 2, 2009
and, as such, only approximately one month of operations is included
in the three months and year ended December 31, 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 Ward County acquisition, based on the actual number
of days from the acquisition closing date to the end of the reported
period, was 309 Mcf/day of natural gas, 411 Bbls/day of oil and 3,330
Gal/day of natural gas liquids during 2009.
(b) The Permian Basin acquisition closed on January 31, 2008 and, as such,
only eleven months of operations are included in the year ended
December 31, 2008. 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 Permian Basin
acquisition, based on the actual number of days from the acquisition
closing date to the end of the reported period, was 552 Mcf/day of
natural gas, 635 Bbls/day of oil and 690 Gal/day of natural gas
liquids during 2008.
(c) Includes production from the Dos Hermanos and Sun TSH acquisitions.
The Sun TSH acquisition closed on August 17, 2009 and, as such, only
approximately four and one half months of operations are included in
the year ended December 31, 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 Sun TSH
acquisition, based on the actual number of days from the acquisition
closing date to the end of the reported period, was 2,995 Mcf/day of
natural gas, 69 Bbls/day of oil and 18,904 Gal/day of natural gas
liquids during 2009.
(d) The Dos Hermanos acquisition closed on July 28, 2008 and, as such,
only five months of operations are included in the year ended December
31, 2008. 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 Dos Hermanos acquisition, based on
the actual number of days from the acquisition closing date to the end
of the reported period, was 2,724 Mcf/day of natural gas and 6,151
Gal/day of natural gas liquids during 2008.
(e) 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 Year Ended
December 31, December 31,
2009(a) 2008 2009(a)(b) 2008(c)(d)
------- ---- ---------- ----------
Revenues:
Natural gas, natural
gas liquids and oil
sales $16,105 $13,157 $46,035 $68,850
Gain (loss) on commodity
cash flow hedges (643) (347) (2,380) 269
Realized gain (loss) on
other commodity
derivative contracts 6,199 3,858 29,993 (6,552)
Unrealized gain (loss)
on other commodity
derivative contracts (2,551) 45,072 (19,043) 39,029
------ ------ ------- ------
Total revenues 19,110 61,740 54,605 101,596
------ ------ ------ -------
Costs and expenses:
Lease operating
expenses 3,419 3,312 12,652 11,112
Depreciation, depletion,
amortization, and
accretion 4,910 4,569 14,610 14,910
Impairment of natural
gas and oil properties 46,336 58,887 110,154 58,887
Selling, general and
administrative expenses 2,414 1,872 10,644 6,715
Production and other
taxes 1,308 1,307 3,845 4,965
----- ----- ----- -----
Total costs and expenses 58,387 69,947 151,905 96,589
------ ------ ------- ------
Income (loss) from
operations (39,277) (8,207) (97,300) 5,007
------- ------ ------- -----
Other income and (expense):
Interest income - 1 - 17
Interest expense (1,242) (1,628) (4,276) (5,491)
Gain on acquisition of
natural gas and oil
properties 1,103 - 6,981 -
Realized loss on interest
rate derivative contracts (663) (17) (1,903) (107)
Unrealized gain (loss) on
interest rate derivative
contracts 376 (2,758) 763 (3,178)
--- ------ --- ------
Total other income (expense) (426) (4,402) 1,565 (8,759)
---- ------ ----- ------
Net loss $(39,703) $(12,609) $(95,735) $(3,752)
======== ======== ======== =======
Net loss per unit:
Common & Class B units
– basic & diluted $(2.31) $(1.00) $(6.74) $(0.32)
====== ====== ====== ======
Weighted average units
outstanding:
Common units –basic &
diluted 16,790,086 12,145,873 13,790,663 11,374,473
========== ========== ========== ==========
Class B units– basic
& diluted 420,000 420,000 420,000 420,000
======= ======= ======= =======
(a) The Ward County acquisition closed on December 2, 2009 and, as such,
only one month of operations is included in the three months and year
ended December 31, 2009.
(b) The Sun TSH acquisition closed on August 17, 2009 and, as such, only
approximately four and one half months of operations are included in
the year ended December 31, 2009.
(c) The Dos Hermanos acquisition closed on July 28, 2008 and, as such,
only five months of operations are included in the year ended December
31, 2008.
(d) The Permian Basin acquisition closed on January 31, 2008 and, as such,
only eleven months of operations are included in the year ended
December 31, 2008.
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31, December 31,
2009 2008
----------- -----------
Assets
Current assets
Cash and cash equivalents $487 $3
Trade accounts receivable, net 8,025 6,083
Derivative assets 16,190 22,184
Other receivables 2,224 2,763
Other current assets 1,317 845
----- ---
Total current assets 28,243 31,878
------ ------
Natural gas and oil properties,
at cost 399,212 284,447
Accumulated depletion, amortization
and accretion (226,687) (102,178)
-------- --------
Natural gas and oil properties evaluated,
net – full cost method 172,525 182,269
------- -------
Other assets
Derivative assets 5,225 15,749
Deferred financing costs 3,298 882
Other assets 1,409 1,784
----- -----
Total assets $210,700 $232,562
======== ========
Liabilities and members' equity
Current liabilities
Accounts payable – trade $766 $2,148
Accounts payable –natural gas and oil 2,299 1,327
Payables to affiliates 1,387 2,555
Deferred swap premium liability 1,334 -
Derivative liabilities 253 486
Phantom unit compensation accrual 4,299 -
Accrued ad valorem taxes 903 34
Accrued expenses 1,178 1,214
----- -----
Total current liabilities 12,419 7,764
Long-term debt 129,800 135,000
Derivative liabilities 2,036 2,313
Deferred swap premium liability 1,739 -
Asset retirement obligations 4,420 2,134
----- -----
Total liabilities 150,414 147,211
------- ------
Commitments and contingencies
Members' equity
Members' capital, 18,416,173 and
12,145,873 common units issued
and outstanding at December 31,
2009 and 2008 59,873 88,550
Class B units, 420,000 issued and
outstanding at December 31, 2009
and 2008 5,930 4,606
Accumulated other comprehensive loss (5,517) (7,805)
------ ------
Total members' equity 60,286 85,351
------ ------
Total liabilities and members' equity $210,700 $232,562
======== ========
Use of Non-GAAP Measures
Adjusted EBITDA
We present Adjusted EBITDA in addition to our reported net 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;
- Unit-based compensation expense; and
- Non-cash portion of phantom unit expense granted to officers.
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 performance and return on capital as compared to those of other companies in our industry. Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, 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 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;
- Unit-based compensation expense; and
- Non-cash portion of phantom unit expense granted to officers.
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 Loss to Adjusted EBITDA (a) and
Distributable Cash Flow
(Unaudited)
(in thousands)
Three Months Ended Year Ended
December 31, December 31,
2009 (b) 2008 2009 (b)(c) 2008 (d)(e)
-------- ---- ----------- -----------
Net loss $(39,703) $(12,609) $(95,735) $(3,752)
Plus:
Interest expense,
including realized
losses on interest
rate derivative
contracts 1,905 1,734 6,179 5,597
Depreciation,
depletion,
amortization and
accretion 4,910 4,569 14,610 14,910
Impairment of natural
gas and oil properties 46,336 58,887 110,154 58,887
Amortization of
premiums paid on
derivative contracts 826 1,058 3,502 4,493
Amortization of value
on derivative
contracts acquired 1,912 186 3,619 733
Unrealized (gains)
losses on other
commodity and interest
rate derivative
contracts 2,175 (42,314) 18,280 (35,851)
Gain on acquisition
of natural gas and
oil properties (1,103) - (6,981) -
Deferred taxes (98) 177 (302) 177
Unit-based compensation
expense 172 869 2,483 3,577
Fair value of phantom
units granted to
officers 1,265 - 4,299 -
Cash settlement of
phantom units
granted to officers (3,906) - (3,906) -
Less:
Interest income - 1 - 17
--- --- --- ---
Adjusted EBITDA $14,691 $12,556 $56,202 $48,754
------- ------- ------- -------
Less:
Interest expense, net 1,905 1,733 6,179 5,580
Drilling, capital
workover and
recompletion
expenditures 1,980 4,814 4,960 18,174
----- ----- ----- ------
Distributable Cash Flow $10,806 $6,009 $45,063 $25,000
======= ====== ======= =======
(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 Ward County acquisition closed on December 2, 2009 and, as such,
only one month of operations is included in the three months and year
ended December 31, 2009.
(c) The Sun TSH acquisition closed on August 17, 2009 and, as such, only
approximately four and one half months of operations are included in
the year ended December 31, 2009.
(d) The Dos Hermanos acquisition closed on July 28, 2008 and, as such,
only five months of operations are included in the year ended December
31, 2008.
(e) The Permian Basin acquisition closed on January 31, 2008 and, as such,
only eleven months of operations are included in the year ended
December 31, 2008.
Adjusted Net Income
We present Adjusted Net Income in addition to our reported net loss 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 officers;
- 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 on the acquisition of natural gas and oil properties and non-cash ceiling test impairment charges will help investors compare results between periods and identify operating trends that could otherwise be masked by these items. In addition, this measure removes the non-cash impact that commodity price and interest rate volatility generates on our GAAP 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 Loss to Adjusted Net Income
(in thousands, except per unit data)
(Unaudited)
Three Months Ended Year Ended
December 31, December 31,
2009 2008 2009 2008
---- ---- ---- ----
Net loss $(39,703) $(12,609) $(95,735) $(3,752)
Plus:
Unrealized (gain) loss on
other commodity derivative
contracts 2,551 (45,072) 19,043 (39,029)
Unrealized (gain) loss on
interest rate derivative
contracts (376) 2,758 (763) 3,178
Fair value of phantom units
granted to officers 1,265 - 4,299 -
Cash settlement of phantom
units granted to officers (3,906) - (3,906) -
Impairment of natural gas and
oil properties 46,336 58,887 110,154 58,887
Gain on acquisition of natural
gas and oil properties (1,103) - (6,981) -
------ --- ------ ---
Total adjustments 44,767 16,573 121,846 23,036
------ ------ ------- ------
Adjusted Net Income $5,064 $3,964 $26,111 $19,284
====== ====== ======= =======
Basic and diluted net loss per unit: $(2.31) $(1.00) $(6.74) $(0.32)
Plus:
Unrealized (gain) loss on
other commodity derivative
contracts 0.15 (3.59) 1.34 (3.31)
Unrealized (gain) loss on
interest rate derivative
contracts (0.02) 0.22 (0.05) 0.27
Fair value of phantom units
granted to officers 0.07 - 0.30 -
Cash settlement of phantom
units granted to officers (0.23) - (0.27) -
Impairment of natural gas and
oil properties 2.69 4.69 7.75 4.99
Gain on acquisition of natural
gas and oil properties (0.06) - (0.49) -
----- --- ----- ---
Basic and diluted adjusted net
income per unit: $0.29 $0.32 $1.84 $1.63
===== ===== ===== =====
FINANCIAL GUIDANCE DISCLOSURES FOR 2010
Overview
Vanguard Natural Resources, LLC and its subsidiaries have prepared this document to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast our operating results for the year ending December 31, 2010. These estimates are based on information available to us as of the date of this filing, and actual results may vary materially from these estimates. We do not undertake any obligation to update these estimates as conditions change or as additional information becomes available.
The estimates provided in this document are based on assumptions that we believe are reasonable. Until our actual results of operations have been compiled and released, all of the estimates and assumptions set forth herein constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this document that address activities, events or developments that we expect, project, believe or anticipate will or may occur in the future, or may have occurred through the date of this filing, including such matters as production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures and other such matters, are forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance, or achievements to be materially different from the results, performance, or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: the volatility of oil and natural gas prices, the unpredictable nature of our drilling results; the reliance upon estimates of proved reserves; operating hazards and uninsured risks; competition; government regulation; and other factors referenced in filings made by us with the Securities and Exchange Commission.
As a matter of policy, we generally do not attempt to provide guidance on:
(a) production which may be obtained through future drilling;
(b) dry hole and abandonment costs that may result from future drilling;
(c) the unrealized effects of ASC Topic 815 "Derivatives and Hedging";
(d) cash or stock bonuses to be paid in the future;
(e) gains or losses from purchases or sales of property and equipment
unless the purchase or sale has been consummated prior to the filing
of the financial guidance; and
(f) capital expenditures related to acquisitions of proved properties
until the expenditures are estimable and likely to occur.
Therefore, the potential impacts of these items are not included in the guidance provided below.
Summary of Estimates
The following table sets forth certain estimates being used by us to model our anticipated results of operations for the fiscal year ending December 31, 2010 based on an average natural gas NYMEX price of $5.59 per MMBtu, average crude oil WTI Sweet price of $75.90 per barrel and an average composite natural gas liquids ("NGL") price of $1.10 per gallon for 2010.
These estimates do not include any acquisitions of additional natural gas or oil properties.
When a single value is provided in the tables below, such value represents the mid-point of the approximate range of estimates. Otherwise, each range of values provided represents the expected low and high estimates for such financial or operating factor.
2010 Range
----------
Average Daily Production:
Appalachian Gas (Mcf) 7,000 - 7,360
Permian Gas (Mcf) 800 - 845
South Texas Gas (Mcf) 5,300 - 5,575
Appalachian Oil (Bbls) 185 - 200
Permian Oil (Bbls) 1,100 - 1,160
South Texas Oil (Bbls) 50 - 55
Appalachian NGL's (Gal) n/a n/a
Permian NGL's (Gal) 665 - 700
South Texas NGL's (Gal) 3,710 - 3,920
Average Daily Production (Mcfe) 24,860 - 26,230
Differentials:
Appalachian Gas (MMBtu) $0.15 - $0.20
Permian Gas (MMBtu) $(0.13) - $(0.17)
South Texas Gas (MMBtu) $(0.12) - $(0.18)
Appalachian Oil (Bbls) $(9.75) - $(10.25)
Permian Oil (Bbls) $(4.00) - $(6.00)
South Texas Oil (Bbls) $(5.00) - $(7.00)
BTU Content:
Appalachian Gas 1,210 - 1,210
Permian Gas 1,001 - 1,001
South Texas Gas 1,005 - 1,005
Costs Variable by Production ($/Mcfe):
Production expenses (including
Severance & Ad Valorem taxes) $2.15 - $2.25
DD&A – oil and gas properties $1.25 - $1.35
Statement of Operations (in thousands):
Total natural gas, natural gas
liquids and oil sales $76,000 - $79,655
Realized gains on other commodity
derivative contracts 20,750 - 20,750
Amortization of premiums paid on
derivative contracts (3,285) - (3,285)
Amortization of value on derivative
contracts acquired (2,000) - (2,000)
------ ------
Total Revenues 91,465 - 95,120
Lease operating expenses (13,775) - (14,500)
Depreciation, depletion, amortization
and accretion (12,000) - (13,000)
General and administrative (3,800) - (4,200)
General and administrative – unit-based
compensation (680) - (680)
Production and other taxes (6,125) - (6,450)
------ ------
Total Costs and Expenses (36,380) - (38,830)
------- -------
Income from Operations 55,085 - 56,290
Interest expense, net (4,730) - (4,730)
Realized losses on interest rate
derivative contracts (2,170) - (2,170)
------ ------
Net Income $48,185 - $49,390
======= =======
Reconciliation of Net Income to Adjusted
EBITDA and Distributable Cash Flow (in
thousands):
Net income $48,185 - $49,390
Plus:
Interest expense including realized
losses on interest rate derivatives 6,900 - 6,900
Depreciation, depletion,
amortization and accretion 12,000 - 13,000
Amortization of premiums paid on
derivative contracts 1,950 - 1,950
Amortization of values on
derivative contracts acquired 2,000 - 2,000
Amortization of unit-based compensation
expense 680 - 680
--- ---
Adjusted EBITDA $71,715 - $73,920
Less:
Interest expense including realized
losses on interest rate derivatives (6,900) - (6,900)
Drilling, recompletions and other
capital expenditures (12,500) - (13,500)
------- -------
Distributable Cash Flow $52,315 - $53,520
======= =======
Weighted Average Units Outstanding
(in thousands):
Basic and Diluted 18,836 - 18,836
CONTACT: Vanguard Natural Resources, LLC |
|
Investor Relations |
|
Lisa Godfrey, 832-327-2234 |
|
(Logo: http://www.newscom.com/cgi-bin/prnh/20091208/LA22476LOGO)
SOURCE Vanguard Natural Resources, LLC
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