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Encore Energy Partners LP Announces Increased Distribution and Fourth Quarter and Full Year 2007 Results

Posted on: Thursday, 14 February 2008, 00:00 CST

Encore Energy Partners LP (NYSE: ENP) (the "Partnership" or "ENP") today announced its unaudited fourth quarter and full year 2007 results.

Summary of Fourth Quarter 2007 Results

The following table highlights certain reported amounts for the fourth quarter of 2007.

(Common units and $ in millions, except per unit amounts.)

Three Months Ended

December 31, 2007

Adjusted EBITDA

$

15.2

Net loss

$

(11.2

)

Distributable cash flow

$

12.3

Total distributions to be paid

$

9.8

Coverage ratio

1.26

Weighted average diluted common units outstanding

24.0

Oil and natural gas revenues

$

23.7

Average daily production volumes (BOE/D)

4,222

Oil as a percentage of total production volumes

79

%

Oil and natural gas capital costs

$

5.6

Adjusted earnings before interest, income taxes, depletion, depreciation, and amortization, non-cash unit-based compensation, and non-cash derivative fair value loss ("Adjusted EBITDA") totaled $15.2 million for the fourth quarter of 2007. For the fourth quarter of 2007, distributable cash flow totaled $12.3 million. A distribution of $9.8 million will be paid on February 14, 2008 to holders of record on February 6, 2008 based on a distribution rate of $0.3875 per unit for the quarter ended December 31, 2007 or $1.55 per unit on an annualized basis. Adjusted EBITDA and distributable cash flow are defined and reconciled to their most directly comparable GAAP measures in the attached financial schedules.

ENP's net loss for the fourth quarter of 2007 was $11.2 million ($0.46 per common unit). The fourth quarter results included a net derivative fair value loss of $16.8 million which is comprised of a loss of $1.4 million related to derivative premium amortization, a $15.8 million loss related to non-cash change in derivative fair value related to future periods, and a gain of $0.4 million related to cash settlements. The fourth quarter of 2007 also included a charge of $1.1 million for compensation expense. Additionally, $0.5 million of expenses related to the acquisition of properties from Encore Acquisition Company ("EAC"), which closed on February 7, 2008, were included in G&A expense for the fourth quarter of 2007.

Jon S. Brumley, Chief Executive Officer and President of Encore Energy Partners GP LLC, stated, "The first full quarter of operations for the partnership was very good. In the early part of the quarter, we had drilling delays and bad weather, but oil and gas production finished above budget in December and currently exceeds our initial first quarter expectations. With the accretion from the recent acquisition from EAC and our unique hedging strategy that protects cash flows to the downside while allowing cash flows to increase as oil and gas prices rise, our partnership is hitting on all cylinders and is positioned well for 2008 and many years to come."

For the fourth quarter of 2007, the Partnership's average realized oil price was $65.66 per barrel ("Bbl") ($25.26 per Bbl negative differential to NYMEX oil price of $90.92) and the average realized natural gas price was $7.19 per thousand cubic feet ("Mcf") ($0.22 per Mcf positive differential to NYMEX natural gas price of $6.97 due to the high MMbtu content of the natural gas). These prices were significantly higher than prices in the third quarter of 2007 and are the primary driver behind the Partnership's increased revenue and the ability of the Partnership to increase its quarterly distribution.

Production and Reserves

Average daily production for the fourth quarter of 2007 was 3,353 Bbls of oil per day and 5,211 Mcf of natural gas per day, for a combined 4,222 barrels of oil equivalent per day ("BOE/D"). This was slightly below expectations by 178 BOE/D due to delayed drilling in the Elk Basin Frontier and Crockett development drilling programs and winter storms in the area of the Elk Basin properties, which caused production delays. Production in December averaged 4,528 BOE/D, which is above the Partnership's previous production expectations.

The production at Elk Basin has been restored following the winter storms. The drilling program at Elk Basin is complete, and the Crockett County drilling is well under way. As a result, ENP expects production to increase in the first quarter of 2008 and to exceed previous estimates.

ENP's total proved oil and natural gas reserves as of December 31, 2007 were 20.9 million barrels of oil equivalent, consisting of 14.4 million Bbls of crude oil, condensate, and natural gas liquids and 39.1 billion cubic feet of natural gas.

At December 31, 2007, oil reserves represented 69 percent of total proved reserves, and 86 percent of total proved reserves are developed. Based on annualized fourth quarter production for 2007, ENP's ratio of reserves to production is approximately 13.5 years for total proved reserves and 11.6 years for proved developed reserves.

Summary of Changes in Proved Reserves

MBOE

Reserves at December 31, 2006

6,288

Purchases of minerals-in-place

15,724

Extensions and discoveries, incl. revisions

293

Production

(1,365)

Reserves at December 31, 2007

20,940

ENP's proved reserve estimates for 100 percent of its properties were prepared by independent petroleum engineers.

Operations Update

The Partnership invested $5.6 million in its capital program during the fourth quarter of 2007.

ENP initiated its first operated drilling program in late October 2007. ENP drilled a total of nine wells in the Frontier formation at Elk Basin, of which six were producing at the end of the year. All nine wells were producing by mid-January 2008. The initial production came in as expected at a first 30 day average rate of 45 BOE/D per well, and their costs were in line with estimates. The field staff in Elk Basin have performed various projects to enhance the base production, including re-activating two Madison wells resulting in a combined excess of 80 BOE/D and performing gas shut-off operations on four Tensleep wells resulting in an average of 5 BOE/D per well. ENP has continued to receive non-operated drilling proposals in the Crockett area from various operators where ENP's gross working interest ranges between eight percent and 50 percent. The operator on these properties has mechanically dry holed one well that will be re-drilled, is completing one well, and is currently drilling another well.

Expected Distributions

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.

As a result of the accretive cash flows from the acquisition, which closed in the first quarter of 2008, and the high prices at which the Partnership was able to lock in downside price protection with hedges in the fourth quarter of 2007 and the first quarter of 2008, the Partnership's management expects to recommend to the Board of Directors of Encore Energy Partners GP LLC an increase in the quarterly distribution to $0.4325 per unit for the quarter ending March 31, 2008 (or $1.73 per unit on an annualized basis) which represents a 11.6 percent increase over the current annualized distribution rate of $1.55 per unit and a 23.6 percent increase over the annualized distribution rate of $1.40 at the time of ENP's initial public offering.

Outlook

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

Average daily production volumes

6,000 to 6,600 BOE/D

Oil and natural gas related capital (first quarter 2008)

$4.0 to $5.0 million

Oil and natural gas related capital (full year 2008)

$10.0 to $11.5 million

Maintenance capital requirements per year -- Long-term

$13.7 million

Lease operations expense

$9.50 to $10.50 per BOE

General and administrative expenses

$4.25 to $4.50 per BOE

Depletion, depreciation, and amortization

$13.25 to $13.75 per BOE

Production, ad valorem, and severance taxes

11.2% of oil and natural gas revenues

Oil differential (% of NYMEX)

19% of NYMEX oil price

Natural gas differential (% of NYMEX)

11% of NYMEX natural gas price

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

The 2006 financial data reported in the attached statements represents historical information of the Permian Basin properties, which were contributed to the Partnership by EAC upon completion of the initial public offering. The results of operations of the Elk Basin properties have been included with those of the Partnership from the date of acquisition in March 2007. The Partnership and the Permian Basin properties were wholly-owned by EAC prior to the closing of the initial public offering.

Conference Call Details

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

Date and Time: Friday, February 15, 2008 at 12:00 p.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 33226345.

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 33226345. The replay will be available through February 29, 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 Elk 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 final prospectus dated September 11, 2007 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

Condensed Consolidated Statements of Operations

(in thousands, except per unit amounts)

Three Months Ended

Year Ended

December 31,

December 31,

2007

2006

2007

2006

(unaudited)

(unaudited)

Revenues:

Oil

$

20,257

$

98

$

58,836

$

409

Natural gas

3,449

2,621

12,269

12,337

Marketing and other

1,596

-

8,582

-

Total revenues

25,302

2,719

79,687

12,746

Expenses:

Production:

Lease operations

4,577

476

13,920

1,673

Production, ad valorem, and severance taxes

2,714

284

8,571

1,226

Depletion, depreciation, and amortization

7,228

330

25,998

1,200

General and administrative

3,039

127

10,707

631

Marketing

1,018

-

6,673

-

Derivative fair value loss

16,815

-

26,301

-

Other operating

228

64

762

246

Total operating expenses

35,619

1,281

92,932

4,976

Operating income (loss)

(10,317

)

1,438

(13,245

)

7,770

Other income (expense):

Interest

(1,021

)

-

(12,294

)

-

Other

122

-

196

-

Total other income (expense)

(899

)

-

(12,098

)

-

Income (loss) before income taxes

(11,216

)

1,438

(25,343

)

7,770

Current income tax benefit (provision)

44

-

(10

)

-

Deferred income tax benefit (provision)

12

(122

)

12

(122

)

Net income (loss)

$

(11,160

)

$

1,316

$

(25,341

)

$

7,648

Net loss allocation:

Limited partners' interest in net loss

$

(10,960

)

$

(18,617

)

General partner's interest in net loss

$

(229

)

$

(389

)

Net loss per common unit:

Basic

$

(0.46

)

$

(0.78

)

Diluted

$

(0.46

)

$

(0.78

)

Weighted average common units outstanding:

Basic

23,992

23,877

Diluted

23,992

23,877

Encore Energy Partners LP

Condensed Consolidated Statements of Cash Flows

(in thousands)

Year Ended

December 31,

2007

2006

(unaudited)

Net income (loss)

$

(25,341

)

$

7,648

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Non-cash and other items

60,860

1,338

Changes in operating assets and liabilities

(25,428

)

1,933

Net cash provided by operating activities

10,091

10,919

Net cash used in investing activities

(337,396

)

(1,036

)

Financing activities:

Net proceeds from issuance of common units

193,461

-

Net proceeds from long-term debt

45,758

-

Contributions

93,658

-

Distributions to owner prior to initial public offering

(4,231

)

(9,883

)

Distributions to unitholders

(1,338

)

-

Net cash provided by (used in) financing activities

327,308

(9,883

)

Increase in cash and cash equivalents

3

-

Cash and cash equivalents, beginning of period

-

-

Cash and cash equivalents, end of period

$

3

$

-

Encore Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands)

December 31,

December 31,

2007

2006

(unaudited)

Total assets

$

390,079

$

26,923

Liabilities (excluding long-term debt)

$

44,443

$

1,204

Long-term debt

47,500

-

Partners' equity / owner's net equity

298,136

25,719

Total liabilities and partners' / owner's net equity

$

390,079

$

26,923

Working capital (a)

$

3,144

$

1,633

__________

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

Encore Energy Partners LP

Selected Operating Results

(unaudited)

Three Months Ended

Year Ended

December 31,

December 31,

2007

2006

2007

2006

Production volumes:

Oil (MBbls)

308

2

1,053

7

Natural gas (MMcf)

479

429

1,869

1,796

Combined (MBOE)

388

73

1,365

306

Daily production:

Oil (Bbls/D)

3,353

18

3,440

18

Natural gas (Mcf/D)

5,211

4,663

5,272

4,920

Combined (BOE/D)

4,222

795

4,318

838

Average prices:

Oil (per Bbl)

$

65.66

$

58.71

$

55.85

$

62.18

Natural gas (per Mcf)

7.19

6.11

6.56

6.87

Combined (per BOE)

61.04

37.16

52.09

41.67

Average costs per BOE:

Lease operations expense

$

11.79

$

6.51

$

10.20

$

5.47

Production, ad valorem, and severance taxes

6.99

3.88

6.28

4.01

Depletion, depreciation, and amortization

18.61

4.51

19.05

3.92

General and administrative

7.83

1.74

7.84

2.06

Derivative fair value loss

43.29

-

19.27

-

Other operating

0.58

0.87

0.56

0.80

Marketing gain

(1.49

)

-

(1.40

)

-

Encore Energy Partners LP

Commodity Derivative Summary as of February 13, 2008

(unaudited)

Oil Derivative Contracts (b)(c)

Average

Average

Downside

Downside

Upside

Upside

Price

Volume

Price

Volume

(per Bbl)

(Bbls)

(per Bbl)

(Bbls)

2008

$

-

-

$

107.60

440

80.00

880

-

-

75.00

2,000

-

-

65.00

500

-

-

2009

$

-

-

$

97.75

440

80.00

880

-

-

75.00

2,250

-

-

65.76

2,250

68.70

1,000

2010

$

-

-

$

93.80

440

80.00

880

-

-

75.00

2,000

-

-

-

-

77.23

1,000

2011

$

-

-

$

95.41

1,440

80.00

1,880

-

-

70.00

1,000

-

-

Natural Gas Derivative Contracts (c)

Average

Average

Downside

Downside

Upside

Upside

Price

Volume

Price

Volume

(per Mcf)

(Mcf)

(per Mcf)

(Mcf)

2008

$

-

-

$

9.83

3,800

8.20

3,800

-

-

7.20

3,800

-

-

2009

$

-

-

$

9.83

3,800

8.20

3,800

-

-

7.20

3,800

-

-

2010

$

-

-

$

9.58

3,800

8.20

3,800

-

-

7.20

3,800

-

-

(b) In addition to above contracts, ENP has sold put contracts for 1,250 Bbls/D at $65.00 in 2009.

(c) 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.

Encore Energy Partners LP

Non-GAAP Financial Measures

(in thousands)

(unaudited)

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

Three Months Ended December 31,

2007

2006

Net income (loss)

$

(11,160

)

$

1,316

Depletion, depreciation, and amortization

7,228

330

Non-cash unit-based compensation expense

1,089

-

Interest expense and other

899

-

Income taxes

(56

)

122

Non-cash derivative fair value loss

17,206

-

Adjusted EBITDA

15,206

1,768

Change in operating assets and liabilities

(3,013

)

360

Other non-cash expenses

19

6

Other expense, net

(899

)

-

Current income taxes

44

-

Purchased options

(15,577

)

-

Cash flows from operating activities

$

(4,220

)

$

2,134

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

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 loss and net cash from operating activities, the Partnership's most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.

Three Months

Ended December 31,

2007

Net loss

$

(11,160

)

Depletion, depreciation, and amortization

7,228

Non-cash unit-based compensation expense

1,089

Non-cash interest and deferred income taxes

75

Non-cash derivative fair value loss

17,206

Development capital

(5,616

)

Accrued development capital

1,631

Capital maintenance reserves

1,810

Distributable Cash Flow

12,263

Change in operating assets and liabilities

(3,013

)

Other non-cash expenses

(68

)

Purchased options

(15,577

)

Development capital

5,616

Accrued development capital

(1,631

)

Capital maintenance reserves

(1,810

)

Cash flows from operating activities

$

(4,220

)

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, cash flow from 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 company because all companies may not calculate Distributable Cash Flow in the same manner.

Source: Business Wire

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