Encore Energy Partners LP Announces Increased Distribution of $0.5755 per Unit Based...

Encore Energy Partners LP Announces Increased Distribution of $0.5755 per Unit Based on New Distribution Formula and First Quarter Results

FORT WORTH, Texas--(Business Wire)--
Encore Energy Partners LP (NYSE: ENP) (the "Partnership" or "ENP")
today announced its first quarter distribution amount of $0.5755 per
unit for the quarter ended March 31, 2008, or $2.302 per unit on an
annualized basis, and unaudited first quarter 2008 results.

Approved Distributions

The Board of Directors of the general partner of the Partnership
has approved a new distribution formula. The Partnership will
distribute to the unitholders 50 percent of the excess distributable
cash flow above: (1) an implied minimum quarterly distribution of
$0.4325 per unit or $1.73 per unit annually and (2) a minimum coverage
ratio of at least 1.10 times cash available for distribution. The new
distribution formula results in a distribution of $0.5755 per unit for
the quarter ended March 31, 2008, or $2.302 per unit on an annualized
basis.

Jon S. Brumley, Chief Executive Officer of Encore Energy Partners
GP LLC, stated, "We are pleased to be offering this new distribution
formula. It highlights what we can do with a first class set of assets
and a savvy hedging program. Because of our hedging program, we can
maintain a minimum distribution of $1.73 and maintain a 1.10 times
coverage ratio even if commodity prices decline significantly. At
current commodity levels, we can maintain a high coverage ratio of 1.4
times, pay down debt, and distribute more cash to the unitholders. We
could not accomplish all of this without a first class set of
properties that are shallow declining and high margin. This
distribution is unique and takes advantage of the positive attributes
of Encore Energy Partners."

Using the distribution criteria outlined above, the Board of
Directors of Encore Energy Partners GP LLC has approved a distribution
of $19.2 million to be paid on or about May 15, 2008 to unitholders of
record on May 9, 2008. The $2.302 per unit annualized distribution
represents a 49 percent increase over the fourth quarter annualized
distribution rate of $1.55 per unit and a 64 percent increase over the
annualized distribution rate of $1.40 per unit at the time of ENP's
initial public offering eight months ago.

Summary of First Quarter 2008 Results

The following table highlights certain reported amounts for the
first quarter of 2008 (common units and $ in millions):

-0-
*T
Three Months Ended
March 31, 2008
-------------------
Adjusted EBITDAX $ 31.8
Net income $ 4.1
Net income excluding certain charges $ 18.8
Distributable cash flow $ 26.7
Total distributions to be paid $ 19.2
Coverage ratio 1.39
Weighted average diluted common units outstanding 28.6
Oil and natural gas revenues $ 44.2
Average daily production volumes (BOE/D) 6,309
Oil as a percentage of total production volumes 74%
Oil and natural gas capital costs $ 5.9
*T

Adjusted earnings before interest, income taxes, depletion,
depreciation, and amortization, non-cash unit-based compensation,
non-cash derivative fair value loss, and exploration expense
("Adjusted EBITDAX") totaled $31.8 million for the first quarter of
2008. For the first quarter of 2008, distributable cash flow totaled
$26.7 million. Adjusted EBITDAX and distributable cash flow are
reconciled to their most directly comparable GAAP measures in the
attached financial schedules.

ENP's net income for the first quarter of 2008 was $4.1 million
($0.01 per diluted common unit). The first quarter results included a
net derivative fair value loss of $15.6 million which comprises a loss
of $2.1 million related to derivative premium amortization, a $13.6
million loss related to non-cash change in derivative fair value
related to future periods, and a gain of $0.2 million related to cash
settlements. The first quarter of 2008 also included a charge of $1.1
million for non-cash compensation expense. Net income excluding
certain charges for the first quarter of 2008 was $18.8 million ($0.52
per diluted common unit). Net income excluding certain charges for the
first quarter of 2008 excludes derivative gains and losses not related
to the current period and non-cash compensation expense. Net income
excluding certain charges is reconciled to its most directly
comparable GAAP measure of net income in the attached financial
schedules.

Depletion, depreciation, and amortization expense for the first
quarter of 2008 was $15.89 per BOE, which was higher than the
previously released guidance of $13.25 to $13.75 per BOE, as the
overall historical cost basis of properties purchased from EAC in the
first quarter of 2008 was higher than previously estimated. Due to the
accounting for transactions between entities under common control, the
properties purchased from EAC are recorded at historical cost instead
of current fair value.

G&A expense for the first quarter of 2008 was $5.09 per BOE, which
was higher than previously released guidance of $4.25 to $4.50 per BOE
due to $0.3 million of additional legal, accounting, and valuation
expenses related to the drop-down of properties from EAC in the first
quarter of 2008. Also, beginning April 1 of each year the amount
payable by ENP to Encore Operating, L.P., a subsidiary of EAC, for
services performed in conjunction with Partnership operations under
its administrative services agreement, increases by the COPAS Wage
Index Adjustment for the current year. Adjusting for this, the amount
payable under the administrative services agreement beginning April 1,
2008 increased to $1.84 per BOE of ENP's production from $1.75 per
BOE.

For the first quarter of 2008, the Partnership's average realized
oil price was $87.30 per barrel ("Bbl") ($10.44 per Bbl negative
differential to the average NYMEX oil price of $97.74) and the average
realized natural gas price was $7.88 per thousand cubic feet ("Mcf")
($0.14 per Mcf negative differential to the average NYMEX natural gas
price of $8.02). These prices were significantly higher than the
Partnership's realized prices in the third and fourth quarters of 2007
and are the primary driver behind the Partnership's increased revenue
and the ability of the Partnership to increase its cash available for
distribution (as discussed above). As a percentage of NYMEX, the
Partnership's oil and natural gas differentials averaged 11 percent
and 2 percent, respectively, both of which are notably tighter than
the Partnership's previously released guidance of 19 percent for oil
and 11 percent for natural gas.

Average daily production for the first quarter of 2008 was 4,682
Bbls of oil per day and 9,760 Mcf of natural gas per day, for a
combined 6,309 BOE per day ("BOE/D"). This was in line with previously
released guidance.

Operations Update

The Partnership invested $5.9 million in its capital programs
during the first quarter of 2008 drilling 25 gross wells (6.9 net),
all of which were successful.

During the third quarter of 2008, the Partnership will be
installing two nitrogen membrane units at the Elk Basin gas plant at a
cost of $1.2 million (gross). These units will remove nitrogen from
the recycled gas stream, enhancing the BTU content of the gas for
plant fuel. This installation will reduce the amount of purchased fuel
gas required for plant operations by approximately half, resulting in
substantial operating cost savings of approximately $0.6 million
(gross) per quarter or $2.4 million (gross) on an annual basis.

Acquisitions Update

On February 7, 2008, the Partnership closed on its previously
announced acquisition of oil and natural gas producing properties in
the Permian and Williston Basins from EAC in exchange for total
consideration of approximately $250.4 million, subject to customary
adjustments. The consideration for the acquisition consisted of $125.4
million in cash and approximately 6.88 million common units
representing limited partner interests in ENP. In order to fund the
cash portion of the purchase price, ENP borrowed under its existing
$300 million revolving credit facility.

Subsequent to the end of the first quarter, the Partnership
acquired an existing net profits interest in its Crockett County
properties in exchange for 283,700 common units of ENP valued at $5.8
million, subject to customary closing adjustments. The deal closed on
May 1, 2008.

Second Quarter 2008 Outlook

The Partnership expects the following for the second quarter of
2008:

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*T
Average daily production volumes 6,000 to 6,600 BOE/D
-------------------------------- -------------------------------------
Oil and natural gas related
capital (second quarter 2008) $2.5 to $3.5 million
-------------------------------- -------------------------------------
Maintenance capital requirements
per year - Long-term $13.7 million
-------------------------------- -------------------------------------
Lease operations expense $10.75 to $11.75 per BOE
-------------------------------- -------------------------------------
G&A expenses (excl non-cash
comp) $3.40 to $3.85 per BOE
-------------------------------- -------------------------------------
Depletion, depreciation, and
amortization $15.75 to $16.25 per BOE
-------------------------------- -------------------------------------
Production, ad valorem, and
severance taxes 11.2% of oil and natural gas revenues
-------------------------------- -------------------------------------
Oil differential (% of NYMEX) -13% of NYMEX oil price
-------------------------------- -------------------------------------
Natural gas differential - dry
gas (% of NYMEX) -11% of NYMEX natural gas price
-------------------------------- -------------------------------------
*T

During the first quarter of 2008, as a result of the increase in
debt levels resulting from the property acquisition, ENP entered into
three-year interest rate swaps whereby it swapped $100 million of
floating rate debt to a weighted average fixed LIBOR rate of 3.06
percent and an expected margin of 1.25 percent on the Partnership's
revolving credit facility.

Because the assets acquired from EAC in the Permian and Williston
Basins were acquired from an affiliate, the acquisition is accounted
for as a transaction between entities under common control, similar to
a pooling, whereby the assets and liabilities are recorded at EAC's
historical cost and the historical financial information is recast to
include the acquired properties. As a result, the historical financial
information of the Partnership has been recast to include the
historical operating results and related production volumes of the
Permian and Williston Basin assets throughout the periods presented.

Conference Call Details

Title: Encore Acquisition Company and Encore Energy Partners LP
Conference Call

Date and Time: Thursday, May 8, 2008 at 11:00 a.m. Central Time

Webcast: Listen to the live broadcast via http://www.encoreenp.com

Telephone: Dial 877-356-9552 ten minutes prior to the scheduled
time and request the conference call by supplying the title specified
above or ID 44369463.

A replay of the conference call will be archived and available via
the Partnership's website at the above web address or by dialing
800-642-1687 and entering conference ID 44369463. The replay will be
available through May 22, 2008. International callers can dial
706-679-0419 for the live broadcast or 706-645-9291 for the replay.

About the Partnership

Encore Energy Partners LP was formed by Encore Acquisition Company
to acquire, exploit, and develop oil and natural gas properties and to
acquire, own, and operate related assets. ENP's assets consist
primarily of producing and non-producing oil and natural gas
properties in the Big Horn Basin of Wyoming and Montana, the Williston
Basin of North Dakota, and the Permian Basin of West Texas.

Cautionary Statement

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 in this
press release relate to, among other things, expected distributions,
the benefits, timing and mix of acquisitions, expected production
volumes, expected expenses, expected taxes, expected capital
expenditures, expected differentials and any other statements that are
not historical facts. 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 properties; the risk of drilling dry holes;
oil and natural gas price volatility; derivative transactions
(including the costs associated therewith); uncertainties in the
estimation of proved, probable, and potential 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
strength and financial resources of ENP's competitors; regulatory
developments; environmental risks; uncertainties in the capital
markets; uncertainties with respect to asset sales; general economic
and business conditions; industry trends; and other factors detailed
in ENP's 2007 Annual Report on 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.

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*T
Encore Energy Partners LP
Condensed Consolidated Statements of Operations
(in thousands, except per unit amounts)
(unaudited)

Three Months Ended
March 31,
------------------
2008 2007 (1)
--------- --------
Revenues:
Oil $37,195 $ 8,160
Natural gas 7,002 4,613
Marketing and other 2,859 1,238
--------- --------
Total revenues 47,056 14,011
--------- --------
Expenses:
Production:
Lease operations 6,058 2,691
Production, ad valorem, and severance taxes 4,798 1,475
Depletion, depreciation, and amortization 9,120 3,706
Exploration 29 31
General and administrative 2,922 555
Marketing 2,393 1,080
Derivative fair value loss 15,587 3,683
Other operating 351 145
--------- --------
Total operating expenses 41,258 13,366
--------- --------
Operating income 5,798 645
--------- --------
Other income (expenses):
Interest (1,640) (1,102)
Other 17 -
--------- --------
Total other income (expenses) (1,623) (1,102)
--------- --------
Income (loss) before income taxes 4,175 (457)
Income tax provision (90) (32)
--------- --------
Net income (loss) $ 4,085 $ (489)
========= ========

Net income allocation:
Limited partners' interest in net income $ 383
=========
General partner's interest in net income $ 35
=========

Net income per common unit:
Basic $ 0.01
Diluted $ 0.01

Weighted average common units outstanding:
Basic 28,273
Diluted 28,632

(1) Because the assets acquired from EAC in the Permian and Williston
Basins were acquired from an affiliate, the acquisition is accounted
for as a transaction between entities under common control, similar
to a pooling, whereby the assets and liabilities are recorded at
EAC's historical cost and the historical financial information is
recast to include the acquired properties. As a result, the
historical financial information of the Partnership has been recast
to include the historical operating results and related production
volumes of the Permian and Williston Basin assets throughout the
periods presented.
*T

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*T
Encore Energy Partners LP
Condensed Consolidated Statements of Cash Flows
(in thousands)
(unaudited)

Three Months Ended
March 31,
-----------------------
2008 2007 (1)
---------- ------------

Net income (loss) $ 4,085 $ (489)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Non-cash and other items 26,384 7,936
Changes in operating assets and
liabilities (7,521) (4,562)
---------- ------------
Net cash provided by operating activities 22,948 2,885
---------- ------------

---------- ------------
Net cash used in investing activities (5,020) (329,670)
---------- ------------

Financing activities:
Net proceeds from long-term debt 117,310 237,500
Distributions to affiliates in connection
with acquisition of Permian and Williston
Basin assets (125,401) -
Distributions to unitholders (9,835) -
Distributions to owner - (3,853)
Contributions from owner in connection
with purchase of Elk Basin assets - 93,658
---------- ------------
Net cash provided by (used in) financing
activities (17,926) 327,305
---------- ------------

Increase in cash and cash equivalents 2 520
Cash and cash equivalents, beginning of
period 3 -
---------- ------------
Cash and cash equivalents, end of period $ 5 $ 520
========== ============

Encore Energy Partners LP
Condensed Consolidated Balance Sheets
(in thousands)
(unaudited)

March 31, December 31,
2008 2007 (1)
---------- ------------

Total assets $ 484,906 $ 497,719
========== ============
Liabilities (excluding long-term debt) $ 56,100 $ 55,206
Long-term debt 165,000 47,500
Partners' equity 263,806 395,013
---------- ------------
Total liabilities and partners' equity $ 484,906 $ 497,719
========== ============

Working capital (a) $ 2,917 $ 2,750

(a) Working capital is defined as current assets minus current
liabilities.

(1) Because the assets acquired from EAC in the Permian and Williston
Basins were acquired from an affiliate, the acquisition is accounted
for as a transaction between entities under common control, similar
to a pooling, whereby the assets and liabilities are recorded at
EAC's historical cost and the historical financial information is
recast to include the acquired properties. As a result, the
historical financial information of the Partnership has been recast
to include the historical operating results and related production
volumes of the Permian and Williston Basin assets throughout the
periods presented.
*T

-0-
*T
Encore Energy Partners LP
Selected Operating Results
(unaudited)

Three Months Ended
March 31,
------------------
2008 2007 (1)
------- ----------
Production volumes:
Oil (MBbls) 426 174
Natural gas (MMcf) 888 665
Combined (MBOE) 574 285

Daily production:
Oil (Bbls/D) 4,682 4,089
Natural gas (Mcf/D) 9,760 7,881
Combined (BOE/D) 6,309 5,402

Average realized prices:
Oil (per Bbl) $87.30 $ 46.84
Natural gas (per Mcf) 7.88 6.93
Combined (per BOE) 76.99 44.80

Average costs per BOE:
Lease operations expense $10.55 $ 9.44
Production, ad valorem, and severance taxes 8.36 5.17
Depletion, depreciation, and amortization 15.89 13.00
Exploration 0.05 0.11
General and administrative 5.09 1.95
Derivative fair value loss 27.15 12.92
Other operating 0.61 0.51
Marketing gain (0.81) (0.55)

(1) Because the assets acquired from EAC in the Permian and Williston
Basins were acquired from an affiliate, the acquisition is accounted
for as a transaction between entities under common control, similar
to a pooling, whereby the assets and liabilities are recorded at
EAC's historical cost and the historical financial information is
recast to include the acquired properties. As a result, the
historical financial information of the Partnership has been recast
to include the historical operating results and related production
volumes of the Permian and Williston Basin assets throughout the
periods presented.
*T

-0-
*T
Encore Energy Partners LP
Commodity Derivative Summary as of May 6, 2008
(unaudited)

Oil Derivative
Contracts (b)
--------------

Daily Average
Daily Average Short Short Daily Average Daily Average
Floor Floor Floor Floor Cap Cap Swap Swap
Period Volume Price Volume Price Volume Price Volume Price
------ ------- ------- ------- ------- ------- ------- ------- -------
(Bbls) (per (Bbls) (per (Bbls) (per (Bbls) (per
Bbl) Bbl) Bbl) Bbl)
May -
Dec.
2008
880 $ 80.00 - $ - 440 $107.60 - $ -
2,000 75.00 - - - - - -
2,500 65.00 (2,000) 65.00 - - - -
2009
880 80.00 - - 440 97.75 - -
2,250 75.00 - - - - - -
1,250 63.40 (1,250) 65.00 - - 1,000 68.70
2010
880 80.00 - - 440 93.80 - -
2,000 75.00 - - 1,000 77.23 - -
2,000 65.00 (2,000) 65.00 - - - -
2011
1,880 80.00 - - 1,440 95.41 - -
1,000 70.00 - - - - - -

Natural Gas Derivative
Contracts (b)
----------------------

Daily Average
Daily Average Short Short Daily Average Daily Average
Period Floor Floor Floor Floor Cap Cap Swap Swap
Volume Price Volume Price Volume Price Volume Price
------ ------- ------- ------- ------- ------- ------- ------- -------
(Mcf) (per (Mcf) (per (Mcf) (per (Mcf) (per
Mcf) Mcf) Mcf) Mcf)
May -
Dec.
2008
3,800 $ 8.20 - $ - 3,800 $ 9.83 - $ -
3,800 7.20 - - - - - -
2009
3,800 8.20 - - 3,800 9.83 - -
3,800 7.20 - - - - - -
2010
3,800 8.20 - - 3,800 9.58 - -
3,800 7.20 - - - - - -

(b) Oil prices represent NYMEX WTI monthly average prices, while gas
prices represent IF Houston Ship Channel prices. The differential
between IF HSC and NYMEX Henry Hub is approximately $0.20 per Mcf.
*T

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*T
Encore Energy Partners LP
Non-GAAP Financial Measures
(in thousands)
(unaudited)

This press release includes a discussion of Adjusted EBITDAX, which is
a non-GAAP financial measure. The following table provides
reconciliations of Adjusted EBITDAX to net income (loss) and net cash
provided by operating activities, the Partnership's most directly
comparable financial performance and liquidity measures calculated
and presented in accordance with GAAP.

Three Months Ended March
31,
-------------------------
2008 2007 (1)
-------------- ----------
Net income (loss) $ 4,085 $ (489)
Depletion, depreciation, and amortization 9,120 3,706
Non-cash unit-based compensation expense 1,130 -
Exploration 29 31
Interest expense and other 1,623 1,102
Income taxes 90 32
Non-cash derivative fair value loss 15,758 3,683
-------------- ----------
Adjusted EBITDAX 31,835 8,065
Change in other operating assets and
liabilities (6,325) (2,511)
Other non-cash expenses 318 539
Interest expense and other (1,623) (1,102)
Cash exploration expense (9) (26)
Current income taxes (52) (29)
Purchased options (1,196) (2,051)
-------------- ----------
Net cash provided by operating activities $ 22,948 $ 2,885
============== ==========

Adjusted EBITDAX is used as a supplemental financial measure by the
Partnership's management and by external users of the Partnership's
financial statements, such as investors, commercial banks, research
analysts, and others, to assess (1) the financial performance of
the Partnership's assets without regard to financing methods,
capital structure, or historical cost basis; (2) the ability of the
Partnership's assets to generate cash sufficient to pay interest
costs and support its indebtedness; (3) the Partnership's operating
performance and return on capital as compared to those of other
entities in the oil and natural gas industry, without regard to
financing or capital structure; and (4) the viability of
acquisitions and capital expenditure projects and the overall rates
of return on alternative investment opportunities.

Adjusted EBITDAX should not be considered an alternative to net
income, operating income, net cash provided by operating activities,
or any other measure of financial performance presented in
accordance with GAAP. The Partnership's definition of Adjusted
EBITDAX may not be comparable to similarly titled measures of
another entity because all companies may not calculate Adjusted
EBITDAX in the same manner.

(1) Because the assets acquired from EAC in the Permian and Williston
Basins were acquired from an affiliate, the acquisition is accounted
for as a transaction between entities under common control, similar
to a pooling, whereby the assets and liabilities are recorded at
EAC's historical cost and the historical financial information is
recast to include the acquired properties. As a result, the
historical financial information of the Partnership has been recast
to include the historical operating results and related production
volumes of the Permian and Williston Basin assets throughout the
periods presented.

This press release also includes a discussion of "Distributable Cash
Flow", which is a non-GAAP financial measure. The following table
provides a reconciliation of distributable cash flow to net income
and net cash provided by operating activities, the Partnership's most
directly comparable financial performance and liquidity measures
calculated and presented in accordance with GAAP.

Three Months
Ended March 31,
2008
--------------
Net income $ 4,085
Depletion, depreciation, and amortization 9,120
Non-cash unit-based compensation expense 1,130
Non-cash derivative fair value loss 15,758
Exploration 29
Development capital (5,849)
Capital maintenance reserves 2,424
--------------
Distributable Cash Flow 26,697
Change in other operating assets and
liabilities (6,325)
Other non-cash expenses 356
Cash exploration expense (9)
Purchased options (1,196)
Development capital 5,849
Capital maintenance reserves (2,424)
--------------
Net cash provided by operating activities $ 22,948
==============

The Partnership believes that Distributable Cash Flow is a useful
measure of the Partnership's financial and operating performance and
its ability to continue to make quarterly distributions.

Distributable Cash Flow should not be considered an alternative to net
income, operating income, net cash provided by operating activities,
or any other measure of financial performance presented in accordance
with GAAP. The Partnership's definition of Distributable Cash Flow
may not be comparable to similarly titled measures of another entity
because all entities may not calculate Distributable Cash Flow in the
same manner.

This press release also includes a discussion of "Net income excluding
certain charges", which is a non-GAAP financial measure. The
following table provides a reconciliation of net income excluding
certain charges to net income, the Partnership's most directly
comparable financial measure calculated and presented in accordance
with GAAP.

Three Months Ended March
31, 2008
-------------------------
Per
Diluted
Total Unit
-------------- ----------
Net income $ 4,085 $ 0.01
Add:
Non-cash unit-based compensation
expense 1,130 0.04
Non-cash derivative fair value loss
excluding premium amortization 13,621 0.47
-------------- ----------
Net income excluding certain charges $ 18,836 $ 0.52
============== ==========

The Partnership believes that the exclusion of these charges enables
it to evaluate operations more effectively period-over-period and to
identify operating trends that could otherwise be masked by the
excluded items.

Net income excluding certain charges should not be considered an
alternative to net income, operating income, net cash provided by
operating activities, or any other measure of financial performance
presented in accordance with GAAP. The Partnership's definition of
net income (loss) excluding certain charges may not be comparable to
similarly titled measures of another entity because all entities may
not calculate net income (loss) excluding certain charges in the same
manner.
*T

Encore Energy Partners LP, Fort Worth, TX
Bob Reeves, 817-339-0918
rcreeves@encoreacq.com
or
Diane Weaver, 817-339-0803
dweaver@encoreacq.com

Copyright Business Wire 2008