Exhibit 99.1

January 20, 2010

Encore Energy Partners LP
777 Main Street, Suite 1400
Fort Worth, Texas 76102

Re:

Encore Energy Partners LP Reserves and Future Net Revenues As of December 31, 2009 SEC Case

Gentlemen:

     At your request, we estimated the proved oil, gas, and natural gas liquids reserves and projected future net revenues associated with these reserves as of December 31, 2009, attributable to the Encore Energy Partners LP (ENP) net interests in properties located in Arkansas, Montana, New Mexico, North Dakota, Oklahoma, Texas, and Wyoming. The properties include approximately 3,797 active producing wells of which 894 are operated by ENP.

     We performed our evaluation, designated as the SEC Case, using unescalated prices, operating expenses, and capital expenditures provided by ENP. Our evaluation was a full determination, reviewing and forecasting 100 percent of these properties. The aggregate results of our evaluation are as follows:

Reserves and Future Net Revenues as of December 31, 2009

										Future Net Revenues
														Discounted at
		Net Reserves												10% Per
		Oil,				Gas,				Undiscounted,				Year,
Reserves Category		MBbls.				MMcf				M$				M$
Proved Producing			26,341				71,094				929,796				470,896
Proved Nonproducing							7,285				11,948				2,563
Proved Developed			26,341				78,379				941,744				473,459
Proved Undeveloped			2,589				6,320				71,556				26,314
Total Proved			28,930				84,699				1,013,300				499,773

Two Houston Center • 909 Fannin Street, Suite 1300 • Houston, Texas 77010

Telephone 713-651-9455 • Telefax 713-654-9914 • e-mail: mail@millerandlents.com

Encore Energy Partners LP		January 20, 2010 Page 2

     Proved reserves and future net revenues were estimated in accordance with the standards of the Securities and Exchange Commission Regulation S-X, Rule 4-10 (a) as shown in the Appendix. Gas volumes for each property are stated at the pressure and temperature bases appropriate for the sales contract or state regulatory authority. Total gas reserves were obtained by summing the reserves for all the individual properties and are, therefore, stated herein at a mixed pressure base. No provisions for the possible consequences of product sales imbalances, if any, were included in our projections since we have received no relevant data.

     Future net revenues as used herein are defined as the total revenues attributable to (1) ENP’s working interest less royalties, overriding royalties, production and ad valorem taxes, operating costs, and future capital expenditures, and (2) ENP’s royalty interest less production and ad valorem taxes. Our projections of future net revenues are shown both undiscounted and discounted at ten percent per annum. The effects of depreciation, depletion, or Federal Income Tax are not considered. Abandonment costs and salvage values were not addressed in our reserve evaluation of these properties. ENP accounts for abandonment costs and salvage values in their Standard Measure of Oil and Gas which is calculated separately from this reserves evaluation. Future costs, if any, for restoration of producing properties to satisfy environmental standards are not deducted from estimates of future net revenues as such are beyond the scope of our assignment. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market value for the estimated reserves. Minor precision inconsistencies in subtotals or totals may exist in the report due to truncation or rounding of aggregated values.

     The 2009 prices used for the reserves projections herein are in accordance with Securities and Exchange Commission standards. The prices of $61.18 per barrel and $3.83 per MMBtu represent the twelve month average of the first-day-of-the-month price for each month within the twelve month period prior to December 31, 2009 as provided by ENP. Price adjustments were made for each property based on differentials between benchmark and actual prices as estimated by ENP and include considerations such as gas Btu content, oil gravity, and transportation charges. Operating costs as of December 31, 2009 were provided by ENP. Costs include per-well and per-unit of production components that were held constant for the remaining economic life of each property. All future capital was unescalated.

     Charts of the proved reserves and related revenues are presented by reserves category, Chart 1; by product, Chart 2; and by region, Chart 3. Forecasts of production and future net revenues for the subject properties are included as exhibits to this report and are identified in the Index to Exhibits. The summary section shows combined proved reserves for all fields and contains cash flows by reserve category. The remaining exhibits are grouped into seven regions by decreasing reserves: (1) West Texas, (2) Big Horn Basin, (3) Williston Basin, (4) Cedar Creek Anticline, (5) Anadarko Area, (6) Ark-La-Tx Area, and (7) New Mexico. Each of these regions contains a one-line summary sorted by operating category, reserves category, field, and well name.

Encore Energy Partners LP		January 20, 2010 Page 3

     The West Texas region consists of various operated and non-operated fields located in the Permian Basin of Texas. Fields include Champmon, Dune, Hutex, Levelland, Nolly/McFarland, North Cowden, Slaughter, Vinegarone and Yates. Also included is a field group called Crockett County that consists of properties located in Crockett County, Texas. Producing fields in Crockett County include Angus, Davidson Ranch, Henderson, Hunt-Baggett, and Ozona which primarily produce gas from the Strawn and Canyon formations.

     The Big Horn Basin properties are located in Park County, Wyoming and Carbon County, Montana. ENP operates the Elk Basin Field complex which consists of Elk Basin Field, Northwest Elk Basin Field, South Elk Basin Field, and Gooseberry Field. The producing horizons in these fields are the Embar-Tensleep, Madison, Frontier, and Big Horn formations. Elk Basin Field is the largest field that is subdivided into units based on the productive formations. Northwest Elk Basin Field and South Elk Basin Field are smaller fields in the area of Elk Basin which account for less than ten percent of the daily production.

     The Williston Basin properties are scattered across the basin in Richland County, Montana and Billings, Dunn, Golden Valley, McKenzie, Stark and Williams Counties, North Dakota. Production is from multiple reservoirs with the majority producing from the Madison formation.

     The Cedar Creek Anticline properties are in Horse Creek Field located in Bowman County, North Dakota producing from the Red River formation and Pine Field located in Wibaux County, Montana producing from the Eagle and Judith formations.

     The Anadarko properties are all non-operated and royalty properties located in various fields in the region. They represent less than two percent of the total ENP reserves.

     The Ark-La-Tx properties are all non-operated and royalty properties located primarily in Chismville Field in Logan County, Arkansas. They represent less than two percent of the total ENP reserves.

     The New Mexico properties are operated, non-operated and royalty properties located in Drinkard, Grayburg Jackson, Loco Hills, and Penrose Skelly fields. They represent less than one percent of the total ENP reserves.

     Proved producing reserves were based primarily on extrapolation of historical performance trends. In those wells producing at high water-cuts, water-oil ratios versus cumulative production trends were used to estimate reserves. We relied mainly on production rate versus time decline curves. Estimates and projections for proved nonproducing and proved undeveloped reserves were based on volumetric calculations or analogies. Reserves estimates from analogies and volumetric calculations are often less certain than reserves estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced.

Encore Energy Partners LP		January 20, 2010 Page 4

     In conducting this evaluation, we relied upon production histories, well test data, well logs, and other engineering and geological data supplied by ENP. To a lesser extent, non-confidential data existing in the files of Miller and Lents, Ltd. and data from commercial services and of public record were used. The operating expenses, ownership interests, reversion provisions, current payout status, and product prices were provided by ENP. We also relied upon ENP’s representations to us of planned schedules and the estimated costs for future well work. None of this information was independently verified as such was beyond the scope of our assignment.

     The evaluations presented in this report, with the exception of those parameters specified by others, reflect our informed judgment based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report.

     Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in ENP or any affiliate of Encore. Our compensation for the required investigations and preparation of this report is not contingent upon the results obtained and reported, and we have not performed other work that would affect our objectivity. Production of this report was supervised by an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

CDR/eb

Appendix
Page 1 of 3

Reserves Definitions In Accordance With
Securities and Exchange Commission Regulation S-X

Reserves

     Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

     Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Proved Oil and Gas Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

1.

The area of the reservoir considered as proved includes:

	a.		The area identified by drilling and limited by fluid contacts, if any, and
	b.		Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

	2.		In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
	3.		Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
	4.		Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

	a.		Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
	b.		The project has been approved for development by all necessary parties and entities, including governmental entities.

Appendix
Page 2 of 3

5.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed Oil and Gas Reserves

     Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

	1.		Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
	2.		Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped Oil and Gas Reserves

     Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

	1.		Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
	2.		Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
	3.		Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined below, or by other evidence using reliable technology establishing reasonable certainty.

               Analogous Reservoir

     Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

	1.		Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
	2.		Same environment of deposition;
	3.		Similar geological structure; and
	4.		Same drive mechanism.

     Reservoir properties must, in aggregate, be no more favorable in the analog than in the reservoir of interest.

Appendix
Page 3 of 3

Probable Reserves

     Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

	1.		When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
	2.		Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
	3.		Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
	4.		See also guidelines in Items 4 and 6 under Possible Reserves.

Possible Reserves

     Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

	1.		When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
	2.		Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
	3.		Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
	4.		The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
	5.		Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
	6.		Pursuant to Item 3 under Proved Oil and Gas Reserves, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.