HOUSTON, March 5 /PRNewswire-FirstCall/ -- Vanguard Natural
Resources, LLC (NYSE Arca: VNR) ("Vanguard" or "the Company") today
reported financial and operational results for the fourth quarter
and full year ended December 31, 2008. Mr. Scott W. Smith,
President and CEO, commented, "During 2008, we successfully
executed our business plan of making accretive acquisitions and
growing our distributable cash flow and our distributions.
Primarily as a result of these successful acquisitions and
secondarily through our participation in this year's development
drilling program, we grew our proved reserves by 62% to 108.5 Bcfe
and increased our production by 40%. This growth positioned us to
raise our annual distribution twice during 2008 to the current rate
of $2.00 per unit on an annual basis, an increase of $0.30 per
unit, or 18%, from the $1.70 rate set forth in our IPO prospectus."
Mr. Smith continued, "While 2009 is likely to be a difficult year
for the energy industry as a whole, we are well-positioned with our
favorable commodity price hedging program and long-life assets to
generate strong cash flows and maintain positive cash distribution
coverage." Mr. Richard Robert, Executive Vice President and CFO,
added, "As shown in the 2009 financial forecast included in this
press release, we expect to generate a significant amount of cash
flow in 2009, which along with our availability under our
reserve-based credit facility, will provide us with the financial
flexibility to pursue an active drilling program and potential
acquisitions in the future. However, in the current environment of
depressed commodity prices, our strategy will be to focus our
efforts on re-completions and enhancing production from our
existing wells to maximize profit with a limited amount of new
drilling. Furthermore, we will continue to consider acquisitions
that deliver returns that are immediately accretive to cash flow.
Absent acquisitions we will concentrate on reducing our debt with
our excess cash." Full Year 2008 Highlights: -- Achieved Adjusted
EBITDA (a non-GAAP financial measure defined below) of $48.8
million, up 61% over $30.4 million in 2007. -- Generated
distributable cash flow (a non-GAAP financial measure defined
below) of $25.0 million during 2008 representing a 163% increase
over the $9.5 million generated in 2007. -- Reported average daily
production of 16,206 thousand cubic feet equivalent (Mcfe) per day
during 2008, up 40% over the average of 11,610 Mcfe/day generated
in 2007. -- Proved reserves increased by 62% in 2008 to 108.5
billion cubic feet equivalent (Bcfe). The additions to proved
reserves in 2008 totaled 47.3 Bcfe (including purchases, extensions
and revisions), replacing 798% of production. -- Recorded a net
loss of $3.8 million for the 2008 year, which included a non-cash
natural gas and oil property impairment charge of $58.9 million
taken in the fourth quarter offset by net unrealized gains from our
commodity and interest rate derivative contracts of $35.9 million.
Excluding the impact of these non-cash charges, our Adjusted Net
Income (a non-GAAP financial measure defined below) was $19.3
million compared to a $2.6 million in 2007. The 2007 Adjusted Net
Income excludes the impact of the loss on extinguishment of debt.
Fourth Quarter 2008 Highlights: -- Generated Adjusted EBITDA of
$12.6 million, up 77% over $7.1 million in the fourth quarter of
2007 and down 9% over third quarter 2008. -- Generated
distributable cash flow of $6.0 million for the three months ended
December 31, 2008 representing a 138% increase over the $2.5
million generated in the fourth quarter of 2007. -- Reported
average production of 18,576 Mcfe per day, up 69% over 10,969
Mcfe/day produced in the fourth quarter of 2007 and up 10% over
third quarter 2008 average volumes. -- Recorded a net loss of $12.6
million for the quarter ended December 31, 2008, compared to net
income of approximately $1.0 million in the 2007 fourth quarter.
The recent quarter included $42.3 million of non-cash unrealized
net gains in our commodity and interest rate derivative contracts
and a non-cash natural gas and oil property impairment charge of
$58.9 million under our full-cost accounting method. Excluding the
impact of these charges, our Adjusted Net Income was $4.0 million
in the fourth quarter of 2008 as compared to $1.0 million in the
fourth quarter of 2007. Year End 2008 Proved Reserves Vanguard's
year-end 2008 proven reserves were 108.5 Bcfe as provided by our
outside reserve engineering firm, Netherland, Sewell &
Associates, Inc. Approximately 75% of the proved reserves are
natural gas and 75% of our reserves are considered proved
developed. At December 31, 2008, we owned working interests in
1,444 gross (958 net) productive wells. In addition to these
productive wells, we own leasehold acreage allowing us to drill new
wells. Approximately 25% or 27.6 Bcfe of our estimated proved
reserves were attributable to our working interests in undeveloped
acreage. In the Appalachian Basin, we have a 40% working interest
in approximately 109,500 gross undeveloped acres surrounding or
adjacent to our existing wells. In South Texas, we own working
interests ranging from 45-50% in 5,300 undeveloped acres
surrounding our existing wells. Impairment Charge Our 2008
full-year and fourth-quarter results included a $58.9 million
impairment charge related to the write-down of our capitalized
costs under full-cost accounting. Under full-cost accounting, our
dry hole and geological costs are capitalized into the full cost
pool, and are subject to amortization and ceiling test limitations.
The ceiling is 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%. Our capitalized costs must
be equal to or less than this ceiling. Because of the precipitous
drop in both oil and gas prices at the end of the 2008 fourth
quarter compared to the prior quarter, the net present value of our
future revenues declined significantly. As a result, as of December
31, 2008, we were required to write-down our full-cost pool down to
the revenue ceiling. This impairment was calculated based on prices
of $5.71 per MMBtu for natural gas and $41.00 per barrel of crude
oil. The impairment calculation did not consider the positive
impact of our commodity derivative positions as generally accepted
accounting principles only allows the inclusion of derivatives
designated as cash flow hedges. Hedging Activities We enter into
derivative transactions in the form of hedging arrangements to
reduce the impact of natural gas and oil price volatility on our
cash flow from operations. As required by our reserve-based credit
facility, we have mitigated this volatility through 2011 by
implementing a hedging program on a portion of our total
anticipated production. Currently, we use fixed-price swaps and
NYMEX collars and put options to hedge natural gas and oil prices.
The following table summarizes commodity derivative contracts in
place at December 31, 2008: 2009 2010 2011 2012 Gas Positions:
Fixed Price Swaps: Notional Volume (MMBtu) 3,629,946 3,236,040
2,962,312 Fixed Price ($/MMBtu) $9.42 $9.10 $7.82 Puts: Notional
Volume (MMBtu) 840,143 - - Floor Price ($/MMBtu) $7.50 $- $-
Collars: Notional Volume (MMBtu) 1,000,000 730,000 - Floor Price
($/MMBtu) $7.50 $8.00 $- Ceiling Price ($/MMBtu) $9.00 $9.30 $-
Total: Notional Volume (MMBtu) 5,470,089 3,996,040 2,96,312 Oil
Positions: Fixed Price Swaps: Notional Volume (Bbls) 181,500
164,250 151,250 144,000 Fixed Price ($/Bbl) $87.23 $85.65 $85.50
$80.00 Collars: Notional Volume (Bbls) 36,500 - - - Floor Price
($/Bbl) $100.00 $- $- $- Ceiling Price ($/Bbl) $127.00 $- $- $-
Total: Notional Volume (Bbls) 218,000 164,250 151,250 144,000 In
February 2009, we liquidated our 2012 oil swap and entered into new
2010 and 2011 natural gas swap and collar transactions.
Specifically, an $8.04 and $7.85 fixed price NYMEX natural gas swap
for January through September 2010 and April through September
2011, respectively, was executed for 2,000 MMBtu/day. In addition,
a 2,000 MMBtu/day NYMEX natural gas collar with a floor price of
$7.50 and a ceiling price of $9.00 for October 2010 through March
2011 and October 2011 through December 2011 was executed. These
natural gas derivatives were set at prices above the current market
by using the proceeds of the liquidation of the 2012 oil swap.
Considering the new derivatives mentioned above, based on our
current drilling plans, approximately 100% of our 2009 natural gas
production is hedged at a floor price of $8.77 per MMBtu and
approximately 84% of our natural gas production is hedged at a
three year weighted average floor price of $8.50 per MMBtu thru
2011. Approximately 81% of our 2009 crude oil production is hedged
at a floor price of $89.37 per barrel and approximately 72% of our
crude oil production is hedged at a three year weighted average
price of $87.13 per barrel thru 2011. Cash Distributions On
February 14, 2009, the Company paid its 2008 fourth-quarter cash
distribution of $0.50 per unit to its unitholders of record. This
quarterly distribution payment was the same amount distributed for
the third quarter of 2008 and represented an increase of $0.075 per
unit, or 18%, over the $0.425 distribution initially set when our
initial public offering was completed on October 29, 2007. Capital
Expenditures Our capital expenditures were $119.5 million in the
year ended December 31, 2008 compared to $26.4 million for the year
ended December 31, 2007. The 2008 expenditures included $100.7
million for the acquisition of natural gas and oil properties in
the Permian Basin and South Texas. It also included $18.2 million
for the drilling and development of natural gas and oil properties
as compared to $12.8 million for the year ended December 31, 2007.
We currently anticipate a capital budget for 2009 of between $6.0
million and $6.5 million, which predominantly consists of
recompletions and workovers of existing wells and a limited number
of new wells in South Texas in the second half of the 2009, all of
which is expected to be funded through cash from operations.
Reserve-based Credit Facility In October 2008, we amended our
reserve-based credit facility which set our borrowing base under
the facility at $175.0 million pursuant to our semi-annual
redetermination and added a new lender. As of December 31, 2008,
our indebtedness under the reserve-based credit facility totaled
$135.0 million. As of March 5, 2009, we had $37 million available
for borrowing under our reserve-based credit facility and had
approximately $4 million in cash. In February 2009, a third
amendment was entered into which amended covenants to allow the
Company to repurchase up to $5.0 million of its own units.
Conference Call Information Vanguard will host a conference call
today to discuss its 2008 full year and fourth quarter results on
Thursday, March 5, 2009 at 11:00 a.m. Eastern Time (10:00 a.m.
Central). To access the call, please dial (800) 366-3908 or (303)
262-2075, 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 until March 19, 2009 and may
be accessed by calling (303) 590-3000 and using the pass code
11126437#. A webcast archive will be available on the Investor
Relations page at http://www.vnrllc.com/ shortly after the call and
will be accessible for approximately 30 days. For more information,
please contact Donna Washburn at DRG&E at (713) 529-6000 or
email at . 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
http://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, 2008 2007 2008
2007 Net Natural Gas Production: Appalachian gas (MMcf) 886 942
3,578 4,044 Permian gas (MMcf) 68 - 218 (a) - South Texas gas
(MMcf) 326 - 566 (b) - Total natural gas production (MMcf) 1,280
942 4,362 4,044 Average Appalachian daily gas production (Mcf/day)
9,628 10,243 9,777 11,080 Average Permian daily gas production
(Mcf/day) 736 - 650 (a) - Average South Texas daily gas production
(Mcf/day) 3,545 - 3,602 (b) - Average Vanguard daily gas production
(Mcf/day) 13,909 10,243 14,029 11,080 Average Natural Gas Sales
Price per Mcf: Net realized gas price, including hedges $9.49 (c)
$9.56 (c) $10.40 (c) $8.92 (c) Net realized gas price, excluding
hedges $7.26 $7.70 $10.30 $8.04 Net Oil Production: Appalachian oil
(Bbls) 16,434 9,549 48,977 30,629 Permian oil (Bbls) 55,136 -
212,599 (a) - Total oil (Bbls) 71,570 9,549 261,576 30,629 Average
Appalachian daily oil production (Bbls/day) 179 104 134 84 Average
Permian daily oil production (Bbls/day) 599 - 635 (a) - Average
Vanguard daily oil production (Bbls/day) 778 104 769 84 Average Oil
Sales Price per Bbl: Net realized oil price, including hedges
$80.57 $60.05 $85.69 $66.08 Net realized oil price, excluding
hedges $54.11 $60.05 $91.48 $66.08 (a) 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 and were not included in the operations of 2007. (b) The south
Texas acquisition closed on July 28, 2008 and, as such, only five
months of operations are included in the year ended December 31,
2008 and were not included in the operations of 2007. (c) Excludes
amortization of premiums paid on non-cash settlement on derivative
contracts. VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) Three Months
Ended Year Ended December 31, December 31, (a)(b) 2008 2007 2008
2007 Revenues: Natural gas and oil sales $13,157,223 $7,831,083
$68,850,004 $34,540,500 Gain (loss) on commodity cash flow hedges
(347,447) 23,611 269,260 (701,675) Gain on other commodity
derivative contracts 48,929,093 - 32,476,472 - Total revenues
61,738,869 7,854,694 101,595,736 33,838,825 Costs and expenses:
Lease operating expenses 3,312,128 1,258,245 11,111,849 5,066,230
Depreciation, depletion, amortization and accretion 4,569,211
2,393,840 14,910,454 8,981,179 Impairment of natural gas and oil
properties 58,886,660 - 58,886,660 - Selling, general and
administrative expenses 1,871,539 1,206,055 6,715,036 3,506,539 Bad
debt expense - - - 1,007,458 Production and other taxes 1,306,686
836,437 4,964,987 2,053,604 Total costs and expenses 69,946,224
5,694,577 96,588,986 20,615,010 Income (loss) from operations
(8,207,355) 2,160,117 5,006,750 13,223,815 Other income and
(expense): Interest income 959 14,182 17,232 61,621 Interest
expense (1,627,961) (1,190,359) (5,490,816) (8,134,600) Loss on
interest rate derivative contracts (2,774,381) - (3,284,514) - Loss
on extinguishment of debt - - - (2,501,528) Total other expense,
net (4,401,383) (1,176,177) (8,758,098) (10,574,507) Net income
(loss) $(12,608,738) $983,940 $(3,751,348) $2,649,308 Net income
(loss) per unit: Common & Class B units - basic $(1.00) $0.10
$(0.32) $0.39 Common & Class B units - diluted $(1.00) $0.10
$(0.32) $0.39 Weighted average units outstanding: Common units -
basic & diluted 12,145,873 9,481,250 11,374,473 6,533,411 Class
B units - basic & diluted 420,000 420,000 420,000 278,945 (a)
The South Texas acquisition closed on July 28, 2008 and as such
only five months of operations are included in the year ended
December 31, 2008 and were not included in the results of 2007. (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 and were not included in the results of
2007. VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES CONSOLIDATED
BALANCE SHEETS (Unaudited) December 31, December 31, 2008 2007
Assets Current assets Cash and cash equivalents $2,616 $3,109,563
Trade accounts receivable, net 6,083,479 3,875,078 Derivative
assets 22,183,648 4,017,085 Other receivables 2,762,730 497,653
Other current assets 845,404 453,198 Total current assets
31,877,877 11,952,577 Property and equipment, net of accumulated
depreciation 184,224 166,455 Natural gas and oil properties, at
cost 284,446,984 135,435,240 Accumulated depletion (102,178,304)
(28,451,891) Natural gas and oil properties evaluated, net - full
cost method 182,268,680 106,983,349 Other assets Derivative assets
15,748,721 1,329,511 Deferred financing costs 881,996 941,833
Non-current deposits 45,963 8,285,883 Other assets 1,554,416
1,519,577 Total assets $232,561,877 $131,179,185 Liabilities and
members' equity Current liabilities Accounts payable - trade
$2,147,664 $1,056,627 Accounts payable - natural gas and oil
1,327,361 257,073 Payables to affiliates 2,554,624 3,838,328
Derivative liabilities 486,576 - Accrued expenses 1,247,606 203,159
Total current liabilities 7,763,831 5,355,187 Long-term debt
135,000,000 37,400,000 Derivative liabilities 2,313,335 5,903,384
Asset retirement obligations 2,133,791 189,711 Total liabilities
147,210,957 48,848,282 Commitments and contingencies Members'
equity Members' capital, 12,145,873 and 10,795,000 common units
issued and outstanding at December 31, 2008 and 2007, respectively
88,550,178 90,257,856 Class B units, 420,000 issued and outstanding
at December 31, 2008 and 2007 4,605,463 2,131,995 Accumulated other
comprehensive loss (7,804,721) (10,058,948) Total members' equity
85,350,920 82,330,903 Total liabilities and members' equity
$232,561,877 $131,179,185 Use of Non-GAAP Measures Adjusted EBITDA
We present Adjusted EBITDA in addition to our reported net income
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; --
Loss on extinguishment of debt; -- Depreciation, depletion and
amortization (including accretion of asset retirement obligations);
-- Impairment of natural gas and oil properties; -- Bad debt
expenses; -- Amortization of premiums paid and non-cash settlements
on derivative contracts; -- Unrealized gains and losses on other
commodity and interest rate derivative contracts; -- Deferred tax
liabilities; -- Unit-based compensation expense; and -- Realized
gains and losses on cancelled derivatives. 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 income in
accordance with GAAP. Distributable cash flow is a non-GAAP
financial measure that is defined as net income (loss) plus: --
Loss on extinguishment of debt; -- Depreciation, depletion and
amortization (including accretion of asset retirement obligations);
-- Impairment of natural gas and oil properties; -- Bad debt
expenses; -- Amortization of premiums paid and non-cash settlements
on derivative contracts; -- Unrealized gains and losses on other
commodity and interest rate derivative contracts; -- Deferred tax
liabilities; -- Unit-based compensation expense; and -- Realized
gains and losses on cancelled derivatives; 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 to Adjusted EBITDA (1)
and Distributable Cash Flow (Unaudited) Three Months Ended Year
Ended December 31, December 31, 2008 2007 2008 (2)(3) 2007 Net
income (loss) $(12,608,738) $983,940 $(3,751,348) $2,649,308 Plus:
Interest expense, including realized loss on interest rate
derivative contracts 1,734,210 1,190,359 5,597,065 8,134,600 Loss
on extinguishment of debt - - - 2,501,528 Depreciation, depletion,
amortization and accretion 4,569,211 2,393,840 14,910,454 8,981,179
Impairment of natural gas and oil properties 58,886,660 -
58,886,660 - Bad debt expense - - - 1,007,458 Amortization of
premiums paid and non-cash settlements on derivative contracts
1,244,690 1,727,121 5,226,465 4,274,120 Unrealized gains on other
commodity and interest rate derivative contracts (42,313,869) -
(35,851,133) - Deferred tax liability 177,000 - 177,000 -
Unit-based compensation expense 868,177 817,217 3,576,558 2,131,995
Realized loss on cancelled derivatives - - - 776,634 Less: Interest
income 959 14,182 17,232 61,621 Adjusted EBITDA $12,556,382
$7,098,295 $48,754,489 $30,395,201 Less: Interest expense, net
1,733,251 1,176,177 5,579,833 8,072,979 Drilling, capital workover
and recompletion expenditures 4,814,478 3,394,709 18,174,285
12,821,192 Distributable Cash Flow $6,008,653 $2,527,409
$25,000,371 $9,501,030 (1) 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. (2) The South Texas
acquisition closed on July 28, 2008 and as such only five months of
operations are included in the year ended December 31, 2008 and
were not included in the results of 2007. (3) 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 and were not included in the results of 2007. 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; and -- Impairment 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 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 to
Adjusted Net Income (Unaudited) Three Months Ended Year Ended
December 31, December 31, 2008 2007 2008 2007 Net income (loss)
$(12,608,738) $983,940 $(3,751,348) $2,649,308 Plus: Unrealized
loss on interest rate derivative contracts 2,758,496 - 3,178,265 -
Impairment of natural gas and oil properties 58,886,660 58,886,660
Less: Unrealized gain on other commodity derivative contracts
(45,072,365) - (39,029,398) - Total adjustments 16,572,791 -
23,035,527 - Adjusted Net Income $3,964,053 $983,940 $19,284,179
$2,649,308 Basic and diluted net income (loss) per unit: $(1.00)
$0.10 $(0.32) $0.39 Plus: Impairment of natural gas and oil
properties 4.69 - 4.99 - Less: Unrealized gain on commodity and
interest rate derivative contracts, net (3.37) - (3.04) - Basic and
diluted adjusted net income per unit: $0.32 $0.10 $1.63 $0.39
FINANCIAL GUIDANCE DISCLOSURES FOR 2009 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, 2009. 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 Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities"; (d) gains or losses from sales
of property and equipment unless the sale has been consummated
prior to the filing of the financial guidance; and (e) capital
expenditures related to acquisitions of proved properties until the
expenditures are estimable and likely to occur; 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, 2009 based on an average natural
gas Henry Hub price of $5.14 per MMBtu and oil WTI Sweet price of
$46.80 per barrel for 2009. 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. See "Supplemental
Information. 2009 Range ---------- Average Daily Production:
Appalachian Gas (Mcf) 8,750 - 9,200 Permian Gas (Mcf) 580 - 610
South Texas Gas (Mcf) 4,150 - 4,370 Appalachian Oil (Bbls) 100 -
105 Permian Oil (Bbls) 595 - 630 South Texas Oil (Bbls) n/a - n/a
Differentials: Appalachian Gas (MMBtu) $0.17 - $0.23 Permian Gas
(MMBtu) $(0.30) - $(0.36) South Texas Gas (MMBtu) $(0.38) - $(0.44)
Appalachian Oil (Bbls) $(9.93) - $(9.93) Permian Oil (Bbls) $(3.26)
- $(3.26) BTU Content: Appalachian Gas 1,170 - 1,170 Permian Gas
1,100 - 1,100 South Texas Gas 1,000 - 1,000 Costs Variable by
Production ($/Mcfe): Production expenses (including Severance &
Ad Valorem taxes) $2.15 - $2.20 DD&A - Oil and gas properties
$2.20 - $2.25 Statement of Operations (in thousands): Total natural
gas and oil sales $38,000 - $40,800 Realized gains on other
commodity derivative contracts 29,050 - 29,050 Premiums paid on
settled derivatives (3,500) - (3,500) Total Revenues 63,550 -
66,350 Lease operating expenses (10,500) - (11,000) Depreciation,
depletion, amortization and accretion (14,500) - (15,000) General
and administrative (3,100) - (3,600) General and administrative -
unit-based compensation (2,580) - (2,580) Production and other
taxes (3,475) - (3,675) Total Costs and Expenses (34,155) -
(35,855) Income from Operations 29,395 - 30,495 Interest expense,
net (4,300) - (4,300) Realized losses on interest rate derivative
contracts (1,500) - (1,500) Net Income $23,595 - $24,695
Reconciliation of Net Income to Adjusted EBITDA and Distributable
Cash Flow (in thousands): Net income $23,595 - $24,695 Plus:
Interest expense including realized losses on interest rate
derivatives 5,800 - 5,800 Depreciation, depletion, amortization and
accretion 14,500 - 15,000 Amortization of premiums paid on
derivative contracts 3,500 - 3,500 Amortization of unit-based
compensation expense 2,580 - 2,580 Adjusted EBITDA $49,975 -
$51,575 Less: Interest expense including realized losses on
interest rate derivatives (5,800) - (5,800) Drilling, recompletions
and other capital expenditures (6,000) - (6,500) Distributable Cash
Flow $38,175 - $39,275 Weighted Average Units Outstanding (in
thousands): Basic and Diluted 12,566 - 12,566 Supplemental
Information: Accounting for Derivatives The following summarizes
information concerning our net positions in open commodity
derivatives applicable to 2009. This list does not include the
Company's open commodity derivatives for periods subsequent to
2009. The settlement prices of commodity derivatives are based on
NYMEX futures prices for collars and put options and are based on
the Columbia Gas Appalachian ("TECO") Index or the Houston Ship
Channel ("HSC") Index as indicated for fixed price swaps. When
varying monthly prices are received through the year the price
indicated below is a weighted average for the year. Fixed Price
Swaps: Gas Oil --- --- MMBtu (a) Price Bbls Price --------------
----- ---- ----- Production Period: 2009 2,663,046 $8.85 TECO
181,500 $87.23 2009 966,900 $10.99 HSC Collars: Gas Oil --- ---
MMBtu (a) Floor Ceiling Bbls Floor Ceiling -------------- -----
------- ---- ----- ------- Production Period: 2009 1,000,000 $7.50
$9.00 36,500 $100.00 $127.00 Puts: Gas MMBtu (a) Floor
-------------- ----- Production Period: 2009 840,143 $7.50 (a) One
MMBtu equals one Mcf at a Btu factor of 1,000. Interest Rates The
following summarizes information concerning our positions in open
interest rate swaps at December 31, 2008. Notional Fixed Amount
Libor Rates Period: January 1, 2009 to December 10, 2010
$10,000,000 1.50% January 1, 2009 to December 20, 2010 $10,000,000
1.85% January 1, 2009 to January 31, 2011 $20,000,000 3.00% January
1, 2009 to March 31, 2011 $20,000,000 2.08% January 1, 2009 to
December 10, 2012 $20,000,000 3.35% January 1, 2009 to January 31,
2013 $20,000,000 2.38% January 1, 2009 to September 10, 2009
$20,000,000 LIBOR 1M vs. (Basis Swap) LIBOR 3M January 1, 2009 to
October 31, 2009 (Basis Swap) $40,000,000 LIBOR 1M vs. LIBOR 3M
CONTACT: Vanguard Natural Resources, LLC Investor Relations Richard
Robert, EVP and CFO, 832-327-2258 DRG&E Jack Lascar/Carol
Coale, 713-529-6600 DATASOURCE: Vanguard Natural Resources, LLC
CONTACT: Richard Robert, EVP and CFO of Vanguard Natural Resources,
LLC, +1-832-327-2258, ; or Jack Lascar or Carol Coale, both of
DRG&E, +1-713-529-6600 Web Site: http://www.vnrllc.com/
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