Encore Energy Partners LP (NYSE:ENP) (the “Partnership” or
“ENP”) today announced its unaudited third quarter 2011
results.
Summary of 2011 and 2010 Third Quarter Results
The following table highlights certain reported amounts for the
third quarter of 2011 and 2010 (common units and dollars in
millions, except quarterly distribution per unit):
Three MonthsEnded
September
30,2011
Three MonthsEnded
September
30,2010
Adjusted EBITDAX (a non-GAAP measure) $ 33.6 $ 29.8 Net income $
96.4 $ 2.4 Adjusted net income (a non-GAAP measure) $ 13.4 $ 11.4
Distributable cash flow (a non-GAAP measure) $ 23.2 $ 24.7 Total
distributions to be paid $ 21.6 $ 22.9 Quarterly distribution per
unit $ 0.47 $ 0.50 Weighted average common units outstanding 45.5
45.3 Total units to which Q3 distributions will be paid 46.0 45.8
Oil and natural gas revenues $ 51.2 $ 42.8 Average daily production
volumes (BOE) 8,991 8,630 Oil volumes as a percentage of total
production volumes 62 % 64 % Oil and natural gas development &
exploration costs $ 7.1 $ 2.0
Adjusted EBITDAX totaled $33.6 million for the third quarter of
2011 and distributable cash flow totaled $23.2 million. Adjusted
EBITDAX and distributable cash flow are non-GAAP financial
measures, which are defined and reconciled to their most directly
comparable GAAP measures in the attached financial schedules.
We reported net income attributable to Encore unitholders for
the quarter of $96.4 million or $2.10 per basic unit compared to a
reported net income of $2.4 million or $0.05 per basic unit in the
third quarter of 2010; however, both quarters included special
items. The recent quarter included $83.4 million of non-cash
unrealized net gains on our commodity and interest rate derivatives
contracts, $1.2 million in one-time material transaction costs
incurred on acquisitions and mergers and $0.8 million in net gains
on acquisitions of oil and natural gas properties. The 2010 third
quarter results included a $9.0 million unrealized net loss on our
commodity and interest rate derivatives contracts.
Excluding the net impact of the specific non-cash and one-time
items mentioned above, Adjusted Net Income attributable to Encore
unitholders (a non-GAAP financial measure defined below) was $13.4
million in the third quarter of 2011 or $0.29 per basic unit, as
compared to $11.4 million or $0.24 per basic unit, in the third
quarter of 2010.
Average daily production for the third quarter of 2011 was 5,555
Bbls of oil per day, 16,912 Mcf of natural gas per day, and 617
Bbls of natural gas liquids per day compared to 5,544 Bbls of oil
per day, 15,755 Mcf of natural gas per day and 460 Bbls of natural
gas liquids per day for the third quarter of 2010, for a combined
8,991 barrels of oil equivalent per day ("BOE/D") in the third
quarter of 2011 compared to 8,630 BOE/D in the third quarter of
2010.
For the third quarter of 2011, the Partnership's average
realized oil price was $75.95 per Bbl after consideration of a
negative fifteen percent ($13.64 per Bbl) oil differential to NYMEX
compared to $66.20 per Bbl and a negative thirteen percent ($9.90
per Bbl) oil differential to NYMEX for the third quarter of 2010.
The average realized natural gas price was $5.66 per Mcf compared
to $4.48 per Mcf in the third quarter of 2010.
Summary of 2011 and 2010 Nine Month Results
The following table highlights certain reported amounts for the
periods indicated (dollars in millions):
Nine MonthsEnded
September
30,2011
Nine MonthsEnded
September
30,2010
Adjusted EBITDAX (a non-GAAP measure) $ 98.2 $ 91.7 Net income $
103.2 $ 46.3 Adjusted net income (a non-GAAP measure) $ 44.5 $ 33.9
Distributable cash flow (a non-GAAP measure) $ 79.1 $ 77.5 Oil and
natural gas revenues $ 152.7 $ 136.1 Average daily production
volumes (BOE) 8,665 8,833 Oil volumes as a percentage of total
production volumes 63 % 63 % Oil and natural gas development &
exploration costs $ 9.9 $ 4.3
Adjusted EBITDAX totaled $98.2 million for the first nine months
of 2011 and distributable cash flow totaled $79.1 million. Adjusted
EBITDAX and distributable cash flow are non-GAAP financial
measures, which are defined and reconciled to their most directly
comparable GAAP measures in the attached financial schedules.
We reported net income attributable to Encore unitholders for
the first nine months of 2011 of $103.2 million or $2.24 per basic
unit compared to a reported net income of $46.3 million or $1.01
per basic unit in the first nine months of 2010; however, both
periods included special items. The 2011 results included $59.5
million of non-cash unrealized net gains in our commodity and
interest rate derivatives contracts, $1.6 million in one-time
material transaction costs incurred on acquisitions and mergers and
$0.8 million in net gains on acquisitions of oil and natural gas
properties. The 2010 results included a $12.4 million unrealized
net gain in our commodity and interest rate derivatives
contracts.
Excluding the net impact of the specific non-cash and one-time
items mentioned above, Adjusted Net Income attributable to Encore
unitholders (a non-GAAP financial measure defined below) was $44.5
million in the first nine months of 2011 or $0.97 per basic unit,
as compared to $33.9 million or $0.73 per basic unit, in the first
nine months of 2010.
Average daily production for the first nine months of 2011 was
5,481 Bbls of oil per day, 16,094 Mcf of natural gas per day, and
501 Bbls of natural gas liquids per day compared to 5,563 Bbls of
oil per day, 16,196 Mcf of natural gas per day and 571 Bbls of
natural gas liquids per day for the first nine months of 2010, for
a combined 8,665 BOE/D in the first nine months of 2011 compared to
8,833 BOE/D in the first nine months of 2010.
For the first nine months of 2011, the Partnership's average
realized oil price was $82.11 per Bbl after consideration of a
negative fourteen percent ($13.20 per Bbl) oil differential to
NYMEX compared to $69.63 per Bbl and a negative ten percent ($7.97
per Bbl) oil differential to NYMEX for the first nine months of
2010. The average realized natural gas price was $4.75 per Mcf for
the first nine months of 2011 compared to $4.84 per Mcf in the
first nine months of 2010.
Recent Events
On July 11, 2011, Vanguard and ENP announced the execution of a
definitive agreement that would result in a merger whereby ENP
would become a wholly-owned subsidiary of Vanguard Natural Gas, LLC
(“VNG”) through a unit-for-unit exchange. Under the terms of the
definitive agreement, ENP’s public unitholders will receive 0.75
Vanguard common units in exchange for each ENP common unit they own
at closing. The transaction will result in approximately 18.4
million additional common units being issued by Vanguard. The terms
of the definitive agreement were unanimously approved by the
members of the ENP Conflicts Committee, who negotiated the terms on
behalf of ENP and is comprised solely of independent directors.
Jefferies & Company, Inc., has issued a fairness
opinion to the ENP Conflicts Committee stating that they believe
the exchange ratio is fair, from a financial point of view, to the
unaffiliated unitholders of ENP. In addition, RBC Capital Markets
has issued a fairness opinion to the Vanguard Conflicts Committee
stating that they believe the exchange ratio is fair, from a
financial point of view, to Vanguard.
The completion of the merger is subject to approval by a
majority of the outstanding ENP common unitholders and also subject
to the approval of the issuance of additional Vanguard common units
in connection with the merger by the affirmative vote of a majority
of the votes cast by Vanguard unitholders. Completion of the
merger, assuming the requisite unitholder votes are obtained and
subject to other customary terms and conditions, is expected to
occur on November 30, 2011. On August 2, 2011, ENP and Vanguard
filed a Registration Statement on Form S-4 (the “Form S-4”) with
the Securities and Exchange Commission (the “SEC”), which has been
declared effective. The Form S-4 incorporates a joint proxy
statement/prospectus which ENP and Vanguard mailed to their
respective unitholders in connection with obtaining unitholder
approval of the proposed merger. Pending completion of the merger,
ENP has agreed to customary restrictions in the way it conducts its
business.
On November 1, 2011, Vanguard and ENP announced that both
companies have established a record date and a meeting date for the
special meetings of unitholders to consider and vote upon the
previously-announced merger agreement.
ENP unitholders of record at the close of business on October
14, 2011 are entitled to notice of and to vote at the special
meeting. The ENP special meeting will be held on Wednesday,
November 30, 2011 at 10:00am Central Time, at the offices of Vinson
& Elkins, 1001 Fannin Street, Suite 2500, Houston, TX
77002.
Vanguard and ENP unitholders are encouraged to read the
definitive proxy statement relating to the special meetings in its
entirety. The definitive proxy statement was filed with the SEC on
October 31, 2011 and was first mailed to unitholders on the same
date.
Vanguard and ENP unitholders who have questions about the merger
or who require assistance in submitting their proxy or voting their
units should contact the proxy solicitor, D.F. King & Co., Inc.
at 1-800-628-8532.
See below for a description of a recently amended credit
facility under Liquidity Update.
Acquisitions
On June 22, 2011, pursuant to two Purchase and Sale Agreements,
ENP agreed to acquire producing oil and natural gas assets in the
Permian Basin in West Texas (the “Purchased Assets”) from a private
seller. ENP and Vanguard agreed to purchase 50% of the Purchased
Assets for an aggregate of $85.0 million and each paid the seller a
non-refundable deposit of $4.25 million. The effective date of this
acquisition is May 1, 2011. We completed this acquisition on July
29, 2011 for an adjusted purchase price of $40.7 million, subject
to customary post-closing adjustments to be determined. The
purchase price was funded with borrowings under our Credit
Agreement. As of September 30, 2011, based on internal reserve
estimates, the interests acquired by ENP have estimated total net
proved reserves of 2.64 million barrels of oil equivalent, of which
approximately 70% are oil and natural gas liquids reserves and are
100% proved developed.
On August 8, 2011, we entered into assignment agreements and
completed the acquisition of certain oil and natural gas properties
located in the Permian Basin of West Texas from a private seller.
The adjusted purchase price for the assets was $14.8 million with
an effective date of May 1, 2011. This acquisition was funded with
borrowings under our Credit Agreement. As of September 30, 2011,
based on internal reserve estimates, the interests acquired by ENP
have estimated total net proved reserves of 1.02 million barrels of
oil equivalent, of which approximately 87% are oil and are 50%
proved developed.
On August 15, 2011, we entered into a definitive agreement with
a private seller for the acquisition of certain oil and natural gas
properties located in Wyoming. The purchase price for the assets
was $28.5 million with an effective date of June 1, 2011. We
completed this acquisition on September 1, 2011 for an adjusted
purchase price of $27.7 million, subject to customary post-closing
adjustments to be determined. The purchase price was funded with
borrowings under our Credit Agreement. As of September 30, 2011,
based on internal reserve estimates, the interests acquired by ENP
have estimated total net proved reserves of 3.91 million barrels of
oil equivalent, of which approximately 65% are natural gas reserves
and are 100% proved developed producing.
On August 31, 2011, we entered into a definitive agreement and
completed the acquisition of certain non-operated working interests
in mature producing oil and natural gas properties located in the
Texas and Louisiana Gulf Coast area from a private seller. The
adjusted purchase price for the assets was $47.6 million with an
effective date of August 1, 2011. This acquisition was funded with
borrowings under our Credit Agreement. As of September 30, 2011,
based on internal reserve estimates, the interests acquired by ENP
have estimated total net proved reserves of 2.13 million barrels of
oil equivalent, of which approximately 83% are oil and natural gas
liquids reserves and are 100% proved developed.
Hedging Activities
We enter into derivative transactions in the form of hedging
arrangements to reduce the impact of oil and natural gas price
volatility on our cash flow from operations. We have mitigated some
of the volatility through 2014 for both crude oil and natural gas
by implementing a hedging program on a portion of our total
anticipated production. At September 30, 2011, the fair value of
commodity derivative contracts was a net asset of approximately
$30.7 million, of which $14.8 million settles during the next
twelve months. Currently, we use fixed-price swaps, basis swaps,
puts, swaptions, three-way collars and NYMEX collars to hedge oil
and natural gas prices.
The following table summarizes new commodity derivative
contracts put in place during the three months ended September 30,
2011:
October 1, –December
31,2011
Year2012
Year 2013
Year2014
Year2015
Gas Positions: Fixed Price Swaps: Notional Volume
(MMBtu) 230,000 915,000 912,500 452,500 — Fixed Price ($/MMBtu) $
4.80 $ 4.80 $ 4.80 $ 4.80 $ —
Basis Swaps: (1) Notional
Volume (MMBtu) 230,000 915,000 912,500 452,500 — Fixed Price
($/MMBtu) ($0.32 ) ($0.32 ) ($0.32 ) ($0.32 ) $ —
Oil
Positions: Fixed Price Swaps: Notional Volume (Bbls) —
36,600 36,500 36,500 — Price ($/Bbl) $ — $ 95.00 $ 95.00 $ 95.00 $
—
Swaptions: Notional Volume (Bbls) — — — — 36,500 Floor
Price ($/Bbl) $ — $ — $ — $ — $ 95.00
Three Way Collars:
Notional Volume (Bbls) 36,800 192,150 191,625 54,750 — Floor Price
($/Bbl) $ 90.00 $ 90.00 $ 90.00 $ 90.00 $ — Ceiling Price ($/Bbl) $
102.63 $ 106.76 $ 106.76 $ 105.00 $ — Short Put Price ($/Bbl) $
70.00 $ 70.00 $ 70.00 $ 70.00 $ —
Basis Swaps: (2) Notional
Volume (MMBtu) 21,000 84,000 84,000 — — Fixed Price ($/MMBtu) $
19.10 $ 15.15 $ 9.60 $ — $ —
(1)
Natural gas basis swap contracts represent
a weighted average differential between prices against Rocky
Mountains (CIGC) and NYMEX Henry Hub prices.
(2)
Oil basis swap contracts represent a
weighted average differential between prices against Light
Louisiana Sweet Crude (LLS) and NYMEX WTI prices.
Interest Rate Swaps
ENP uses derivative instruments in the form of interest rate
swaps, which hedge risk related to interest rate fluctuation,
whereby the interest due on certain floating rate debt under the
Credit Agreement is converted to a weighted average fixed rate. On
September 21, 2011, we increased the existing $50 million swap to
$75 million and extended the maturity to March 7, 2016, allowing us
to decrease the fixed Libor rate from 2.42% to 1.08%. The following
table summarizes ENP’s open interest rate swap as of September 30,
2011, which was entered into with Bank of America, N.A.:
Term:
NotionalAmount
FixedLiborRates
FixedLiborRates
October 1, 2011 to March 7, 2016 (1)
$ 75,000 1.08 % 1-month LIBOR
(1)
ENP entered into this interest rate swap
on September 21, 2011, and the terms became effective on October 7,
2011.
For a summary of all commodity and interest rate derivative
contracts in place at September 30, 2011, please refer to our third
quarter Form 10-Q which is expected to be filed on November 8,
2011.
Cash Distributions
On November 14, 2011, Encore will pay a third quarter cash
distribution of $0.47 per unit to its unitholders of record as of
November 7, 2011. This quarterly distribution payment is unchanged
from the amount distributed for the second quarter of 2011 and a
$0.02 decrease from the $0.49 per unit quarterly distributions paid
in the first quarter of 2011.
Capital Expenditures
Capital expenditures for the drilling, capital workover and
recompletion of oil and natural gas properties were approximately
$7.1 million in the third quarter of 2011 compared to $2.0 million
for the comparable quarter of 2010. During the three months ended
September 30, 2011, a substantial portion of these capital
expenditures were spent on drilling three wells in the Big Horn
Basin amounting to approximately $3.4 million and on drilling of
non-operated properties. An additional $3.3 million was spent on
maintenance capital projects and recompletions in the Big Horn
Basin, Permian Basin and Williston Basin. Capital spending in the
third quarter was below expectations because of the early release
of the drilling rig in the Big Horn Basin in September 2011.
Liquidity Update
At September 30, 2011, ENP had $356.0 million outstanding under
its credit agreement and $44.0 million of remaining availability.
As of November 2, 2011 there were $346.0 million of outstanding
borrowings and $54.0 million of borrowing capacity under the credit
agreement.
On September 30, 2011, Vanguard entered into a Third Amended and
Restated Credit Agreement (the “Amended Credit Agreement”) which
amends and restates its existing facility. The execution of the
Amended Credit Agreement will only be effective upon the
satisfaction of certain conditions including, but not limited to,
the successful consummation of the previously announced merger
between Vanguard and ENP. The Amended Credit Agreement provides for
an initial borrowing base of $765 million and a maturity of October
31, 2016. Under the terms of the Amended Credit Agreement, Vanguard
has agreed that a portion of the proceeds of the credit facility
created by this Amended Credit Agreement will be used to repay
amounts outstanding under our credit agreement.
As shown on the September 30, 2011 balance sheet, all borrowings
under the credit agreement are reflected as current liabilities.
This is due to the credit agreement maturing on March 7, 2012. As
discussed above, on September 30, 2011, Vanguard entered into the
Amended Credit Agreement and has agreed that a portion of the
proceeds of the credit facility created by this Amended Credit
Agreement will be used to repay amounts outstanding under our
credit agreement.
Conference Call Information
Vanguard and Encore will host a joint conference call today to
discuss Vanguard and Encore’s third quarter results at 10:30 a.m.
Eastern Time (9:30 a.m. Central). To access the call, please dial
(800) 762-8908 or (480) 629-9677, 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 3, 2011 and may be accessed by calling (303)
590-3030 and using the pass code 4483164#. 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 Encore Energy Partners LP
Encore Energy Partners LP is a publicly traded master limited
partnership focused on the acquisition, production, and development
of oil and natural gas properties. ENP’s assets consist primarily
of producing and non-producing oil and natural gas properties in
the Big Horn Basin in Wyoming and Montana, the Williston Basin in
North Dakota and Montana, the Permian Basin in West Texas and New
Mexico, and the Arkoma Basin in Arkansas and Oklahoma. By virtue of
Vanguard Natural Resources, LLC’s (NYSE: VNR) (“Vanguard”)
acquisition of Encore Energy Partners GP LLC and certain limited
partner interests in Encore Energy Partners LP from Denbury
Resources Inc. (NYSE: DNR) on December 31, 2010, Vanguard now owns
approximately 46% of the common units of ENP. More information on
Vanguard can be found at www.vnrllc.com. More information on ENP
can be found at www.encoreenp.com.
Forward-Looking Statements
This press release includes forward-looking statements, which
give ENP's current expectations or forecasts of future events based
on currently available information. Forward-looking statements are
statements that are not historical facts, including ENP's
evaluation of strategic alternatives, possible future transactions
(including the timing or effects thereof), potential changes in
ENP's current business plan, increases in unitholder value expected
distributions, the benefits, timing, and mix of acquisitions,
expected production volumes, expected expenses, expected taxes,
expected capital expenditures, and expected differentials. The
assumptions of management and the future performance of ENP are
subject to a wide range of business risks and uncertainties and
there is no assurance that these statements and projections will be
met. Factors that could affect ENP's business include, but are not
limited to: the risks associated with drilling of oil and natural
gas wells; ENP's ability to find, acquire, market, develop, and
produce new reserves; the risk of drilling dry holes; oil and
natural gas price volatility; derivative transactions (including
the costs associated therewith and the ability of counterparties to
perform thereunder); uncertainties in the estimation of proved,
probable, and possible reserves and in the projection of future
rates of production and reserve growth; inaccuracies in ENP's
assumptions regarding items of income and expense and the level of
capital expenditures; uncertainties in the timing of exploitation
expenditures; operating hazards attendant to the oil and natural
gas business; drilling and completion losses that are generally not
recoverable from third parties or insurance; potential mechanical
failure or underperformance of significant wells; climatic
conditions; availability and cost of material and equipment; the
risks associated with operating in a limited number of geographic
areas; actions or inactions of third-party operators of ENP's
properties; diversion of management's attention from existing
operations while pursuing acquisitions; availability of capital;
the ability of lenders to fulfill their commitments; the strength
and financial resources of ENP's competitors; regulatory
developments; environmental risks; uncertainties in the capital
markets; general economic and business conditions (including the
effects of the worldwide economic recession); industry trends; and
other factors detailed in ENP's most recent Form 10-K and other
filings with the Securities and Exchange Commission. If one or more
of these risks or uncertainties materialize (or the consequences of
such a development changes), or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those
forecasted or expected. ENP undertakes no obligation to publicly
update or revise any forward-looking statements.
ENCORE ENERGY PARTNERS LP
OPERATING STATISTICS
(unaudited)
Three Months EndedSeptember
30,
Nine Months EndedSeptember
30,
2011 2010 2011 2010 Average realized
prices: Oil ($/Bbl) $ 75.95 $ 66.20 $ 82.11 $ 69.63 Natural gas
($/Mcf) $ 5.66 $ 4.48 $ 4.75 $ 4.84 Natural gas liquids ($/Bbl) $
62.59 $ 59.54 $ 65.67 $ 57.68 Combined ($/BOE) $ 61.87 $ 53.89 $
64.56 $ 56.45
Total production volumes: Oil (MBbls)
511 510 1,496 1,519 Natural gas (MMcf) 1,556 1,449 4,394 4,421
Natural gas liquids (MBbls) 57 42 137 156 Combined (MBOE) 827 794
2,365 2,411
Average daily production volumes: Oil
(Bbls/D) 5,555 5,544 5,481 5,563 Natural gas (Mcf/D) 16,912 15,755
16,094 16,196 Natural gas liquids (Bbls/D) 617 460 501 571 Combined
(BOE/D) 8,991 8,630 8,665 8,833
Average NYMEX prices:
Oil (per Bbl) $ 89.59 $ 76.10 $ 95.31 $ 77.60 Natural gas (per Mcf)
$ 4.17 $ 4.24 $ 4.19 $ 4.54
ENCORE ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF
OPERATIONS
(in thousands, except per unit
amounts)
(unaudited)
Three months endedSeptember
30,
Nine months endedSeptember
30
2011 2010 2011 2010
Revenues: Oil $ 38,814 $ 33,765 $ 122,869 $ 105,732 Natural gas
8,811 6,497 20,872 21,407 Natural gas liquids 3,554 2,521 8,978
9,001 Marketing 126 60 207 207 Commodity derivative fair value gain
(loss) - realized (2,818 ) 1,342 (7,616 ) 1,959 Commodity
derivative fair value gain (loss) - unrealized 82,914
(8,922 ) 58,318 12,521 Total revenues 131,401
35,263 203,628 150,827 Expenses:
Production: Lease operating 10,451 9,268 29,198 30,907 Production
and other taxes 5,647 4,752 15,672 14,951 Depletion, depreciation,
amortization, and accretion 12,500 12,782 35,568 38,472 Exploration
- 53 - 129 General and administrative 4,451 2,817
12,710 10,088 Total expenses 33,049
29,672 93,148 94,547 Operating income
98,352 5,591 110,480 56,280 Other
income (expenses): Interest (2,646 ) (2,303 ) (7,030 ) (6,987 )
Interest rate derivative fair value loss - realized (445 ) (974 )
(1,858 ) (2,925 ) Interest rate derivative fair value gain (loss) -
unrealized 523 (29 ) 1,146 (133 ) Net gain on acquisitions of oil
and natural gas properties 815 - 815 - Other 70 9
79 47 Total other expenses (1,683 )
(3,297 ) (6,848 ) (9,998 ) Income before
income taxes 96,669 2,294 103,632 46,282 Income tax provision
(220 ) 147 (415 ) 36 Net income
$ 96,449 $ 2,441 $ 103,217 $ 46,318 Net income allocation:
Limited partners' interest in net income $ 95,391 $ 2,419 $ 102,084
$ 45,813 General partner's interest in net income $ 1,058 $ 22 $
1,133 $ 505 Net income per common unit: Basic $ 2.10 $ 0.05
$ 2.24 $ 1.01 Diluted $ 2.10 $ 0.05 $ 2.24 $ 1.01 Weighted
average common units outstanding: Basic 45,487 45,342 45,481 45,328
Diluted 45,487 45,342 45,481 45,336
ENCORE ENERGY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit amounts)
September 30, December 31, 2011
2010 (unaudited)
Assets Current assets: Cash
and cash equivalents $ 651 $ 1,380 Accounts receivable - trade
34,260 22,795 Derivatives 14,813 2,604 Other 2,172
470
Total current assets 51,896
27,249 Properties and equipment, at cost - successful
efforts method: Proved properties, including wells and related
equipment 1,002,851 857,999 Unproved properties 41 17 Accumulated
depletion, depreciation, and amortization (294,014 )
(259,575 ) 708,878 598,441 Other
property and equipment 1,694 1,327 Accumulated depreciation
(669 ) (613 ) 1,025 714 Goodwill
9,290 9,290 Other intangibles, net 2,784 3,012 Derivatives 15,884
836 Other 318 1,778 Total assets $
790,075 $ 641,320
Liabilities and partners’
equity Current liabilities: Accounts payable: Trade $
2,021 $ 2,103 Affiliate 1,490 98 Accrued liabilities: Lease
operating 4,717 4,550 Development capital 1,736 890 Interest 375
298 Production and other taxes 14,235 10,109 Derivatives 66 3,530
Oil and natural gas revenues payable 3,276 1,730 Credit agreement
356,000 - Other 2,497 1,278
Total
current liabilities 386,413 24,586 Derivatives 241 20,681
Future abandonment cost, net of current portion 16,785 13,080
Deferred taxes 63 11 Credit agreement -
234,000
Total liabilities 403,502
292,358
Commitments and contingencies
Partners' equity: Limited partners - public, 24,560,808 and
24,417,542 common units issued and outstanding, respectively
349,912 340,126 Limited partners - affiliates, 20,924,055 common
units issued and outstanding 36,674 10,125 General partner -
504,851 general partner units issued and outstanding 309 (94 )
Accumulated other comprehensive loss (322 ) (1,195 )
Total partners' equity 386,573 348,962
Total liabilities and partners' equity $ 790,075
$ 641,320
Non-GAAP Financial Measure
Adjusted EBITDAX
We define Adjusted EBITDAX as net income plus:
- Net interest expense, including
write-off of deferred financing fees and realized gains and losses
on interest rate derivative contracts;
- Depletion, depreciation and
amortization (including accretion of asset retirement
obligations);
- Exploration expense;
- Amortization of premiums paid on
derivative contracts;
- Unrealized gains and losses on
commodity and interest rate derivative contracts;
- Net gain on acquisitions of oil and
natural gas properties;
- Income taxes;
- Unit-based compensation expense;
- Material transaction costs incurred on
acquisitions and mergers; and
- Non-cash debt related expense paid by
previous owner.
Adjusted EBITDAX is a significant performance metric 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
EBITDAX 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.
Our Adjusted EBITDAX should not be considered as an alternative
to net income, operating income, cash flow from operating
activities, or any other measure of financial performance or
liquidity presented in accordance with GAAP. Our Adjusted EBITDAX
excludes some, but not all, items that affect net income and
operating income and these measures may vary among other companies.
Therefore, our Adjusted EBITDAX may not be comparable to similarly
titled measures of other companies.
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 plus:
- Depletion, depreciation and
amortization (including accretion of asset retirement
obligations);
- Exploration expense;
- Amortization of premiums paid on
derivative contracts;
- Unrealized gains and losses on other
commodity and interest rate derivative contracts;
- Net gain on acquisitions of oil and
natural gas properties;
- Unit-based compensation expense;
- Material transaction costs incurred on
acquisitions and mergers; and
- Non-cash debt related expense paid by
previous owner
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.
ENCORE ENERGY PARTNERS LP
Reconciliation of Net Income to
Adjusted EBITDAX and Distributable Cash Flow
(in thousands)
(unaudited)
Three Months EndedSeptember
30,
Nine Months EndedSeptember
30,
2011 2010 2011
2010 Net income $ 96,449 $ 2,441 $ 103,217 $ 46,318
Plus: Net interest expense, including realized losses on interest
rate derivative contracts 3,092 3,268 8,887 9,865 Depletion,
depreciation and amortization 12,500 12,782 35,568 38,472
Exploration expense - 53 - 129 Amortization of premiums paid on
derivative contracts 4,210 2,474 8,163 7,342 Unrealized (gains)
losses on commodity and interest rate derivative contracts (83,437
) 8,951 (59,464 ) (12,388 ) Net gain on acquisitions of oil and
natural gas properties (815 ) - (815 ) - Income taxes 220 (147 )
415 (36 ) Unit-based compensation expense 222 2 667 1,043 Material
transaction costs incurred on acquisitions and mergers 1,182 -
1,589 - Non-cash debt related expense paid by previous owner
- - - 938
Adjusted EBITDAX $ 33,623 $
29,824 $ 98,227 $ 91,683 Less: Interest expense, net 3,092 3,268
8,887 9,865 Income taxes 220 (147 ) 415 (36 ) Drilling, capital
workover and recompletion expenditures 7,139 2,051
9,852 4,314
Distributable Cash Flow $ 23,172 $
24,652 $ 79,073 $ 77,540
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 plus:
- Unrealized gains and losses on other
commodity derivative contracts;
- Unrealized gains and losses on interest
rate derivative contracts;
- Net gain on acquisitions of oil and
natural gas properties; and
- Material transaction costs incurred on
acquisitions and mergers.
This information is provided because management believes
exclusion of the impact of our unrealized derivatives not accounted
for as cash flow hedges, net gain on acquisitions of oil and
natural gas properties and material transaction costs incurred on
acquisitions and mergers 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.
ENCORE ENERGY PARTNERS LP
Reconciliation of Net Income to
Adjusted Net Income
(in thousands, except per unit
amounts)
(unaudited)
Three Months EndedSeptember
30,
Nine Months EndedSeptember
30,
2011 2010 2011
2010 Net income $ 96,449 $ 2,441 $ 103,217 $
46,318 Plus: Unrealized (gains) losses on commodity and interest
rate derivative contracts (83,437 ) 8,951 (59,464 ) (12,388 ) Net
gain on acquisitions of oil and natural gas properties (815 ) -
(815 ) - Material transaction costs incurred on acquisitions and
mergers 1,182 - 1,589 -
Adjusted Net Income $ 13,379 $ 11,392 $ 44,527
$ 33,930
Basic net income per unit: $
2.10 $ 0.05 $ 2.24 $ 1.01 Plus: Unrealized (gains) losses on
commodity and interest rate derivative contracts (1.81 ) 0.19 (1.29
) (0.28 ) Gain on acquisitions of oil and natural gas properties
(0.02 ) - (0.01 ) - Material transaction costs incurred on
acquisitions and mergers 0.02 - 0.03
-
Basic adjusted net income per unit: $
0.29 $ 0.24 $ 0.97 $ 0.73
Important Information for Investors
This communication does not constitute an offer to sell any
securities. Any such offer will be made only by means of a
prospectus, and only if and when a definitive agreement has been
entered into by Encore Energy Partners, LP (“ENP”) and Vanguard
Natural Resources, LLC (“VNR”), pursuant to a registration
statement filed with the Securities and Exchange Commission
(“SEC”). If the proposed merger is approved, a registration
statement of VNR, which will include a joint proxy statement of ENP
and VNR, which will also constitute a prospectus of
VNR, and other materials, will be filed with the SEC. IF AND
WHEN APPLICABLE, INVESTORS AND SECURITY HOLDERS ARE URGED TO
CAREFULLY READ THE DOCUMENTS FILED WITH THE SEC REGARDING THE
PROPOSED TRANSACTION WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL
CONTAIN IMPORTANT INFORMATION ABOUT ENP, VNR AND THE PROPOSED
MERGER. If and when applicable, investors and security holders may
obtain a free copy of the joint proxy statement / prospectus and
other documents containing information about ENP and VNR, without
charge, at the SEC’s website at www.sec.gov
Grafico Azioni Encore Energy Partners Lp (NYSE:ENP)
Storico
Da Apr 2024 a Mag 2024
Grafico Azioni Encore Energy Partners Lp (NYSE:ENP)
Storico
Da Mag 2023 a Mag 2024