Exhibit 99.1

January 20, 2010

Encore Acquisition Company
777 Main Street, Suite 1400
Fort Worth, Texas 76102

		Re:		Encore Acquisition Company
				Reserves and Future Net Revenues
				As of December 31, 2009
				SEC Case

Gentlemen:

     At your request, we estimated the proved reserves and projected future net revenues as of December 31, 2009, attributable to the Encore Acquisition Company (Encore) net interests in properties located in Arkansas, Kansas, Louisiana, Michigan, Mississippi, Montana, North Dakota, New Mexico, Oklahoma, Texas, Utah, and Wyoming. The properties include approximately 7,044 active producing wells of which 2,918 are operated by Encore.

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

Reserves and Future Net Revenues as of December 31, 2009

		Net Reserves								Future Net Revenues
														Discounted at
														10% Per
		Oil,				Gas,				Undiscounted,				Year,
Reserves Category		MBbls.				MMcf				M$				M$
Proved Producing			118,887				312,179				4,052,469				2,010,840
Proved Nonproducing			2,514				10,243				125,523				38,167
Proved Undeveloped			25,693				116,650				811,185				189,240
EAC Corporate Indirect Costs											-178,046				-97,210
Total Proved			147,094				439,072				4,811,131				2,141,037

Two Houston Center  •  909 Fannin Street , Suite 1300  • Houston , Texas 77010
telephone 713-651-9455   •  TELEFAX 713-654-9914  •  e-mail: mail@millerandients.com

Encore Acquisition Company		January 20, 2010
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     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) Encore’s working interest less royalties, overriding royalties, production and ad valorem taxes, operating costs, net profits interest payments, future capital expenditures, and (2) Encore’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 year. Also included at the aggregate level is a line item referred to as EAC Corporate Indirect Costs, which represents both non-recurring overhead capital and expense associated with the capital spending program over the next five years and recurring overhead expense associated with production maintenance. The effects of depreciation, depletion, or Federal Income Tax are not considered. Abandonment costs and salvage values were not addressed in our reserves evaluation of these properties. Encore 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 Encore. Price adjustments were made for each property based on differentials between benchmark and actual prices as estimated by Encore and include considerations such as gas Btu content, oil gravity, and transportation charges. Operating costs as of December 31, 2009 were provided by Encore. 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. Please note that in Chart 2, the net profits interest (NPI) payments are correctly shown as negatives to Encore in the tabular values, but are considered an integral part of the net reserves and revenues pie.

Encore Acquisition Company		January 20, 2010
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     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 reserves category. The remaining exhibits are grouped into nine Encore regions. The first five are considered their Northern region which includes (1) Cedar Creek Anticline, (2) Williston Basin, (3) Big Horn Basin, (4) Paradox Basin, and (5) Powder River Basin. The next four are considered their Southern region and includes (6) West Texas, (7) Ark-La-Tex Area, (8) Anadarko Area, and (9) New Mexico. Each of these regions contains a one-line summary by well.

     Cedar Creek Anticline (CCA) is a structure 100 miles long by six miles wide located in southeastern Montana and western North Dakota. Primary producing formations are the Red River at a depth of 8,800 feet, the Stony Mountain at 8,600 feet, and the Interlake at 8,300 feet. The productive intervals are geologically continuous, but CCA has been subdivided into several regulatory fields. These fields include Bloomfield, Cabin Creek, Cedar Creek, Coral Creek, Gas City, Glendive, Horse Creek, Little Beaver, Little Beaver East, Monarch, Pennel, Pine North, Pine South, Wills Creek, and Wills Creek South. Exhibits for the CCA properties are summarized by operating category, reserves category, and field.

     In the CCA fields, a large portion of properties owned by Encore are burdened by Net Profits Interest (NPI) payments. The modeling and calculation of future NPI payments and the reserves attributable to these payments are provided by Encore. At Encore’s request, Miller and Lents, Ltd. audited the spreadsheet model used to estimate future NPI payments and reserves. We verified model inputs such as interests, payout balances, and the forecasted cash flows from the economic model for all NPI properties. We reviewed the accounting concepts and framework of the model which was developed to project net profit and calculate NPI payments. Two accounting elements in the model are Statements and Keycodes. Statements represent each NPI contract. We did not review those land contracts that specify the NPI payments, but accepted Encore’s interpretation of each contract’s payment provision. Keycodes are unique numbers assigned to fields, parts of fields or groups of fields. Each producing area is assigned to only one keycode. Statements combine and consolidate projected future revenues by grouping one or more Keycodes for the purpose of determining profit and making NPI payments. The total NPI payment for each Keycode is converted to barrels and Mcf based on product prices. Product volumes are split in proportion to their contribution to pre-NPI total revenue. Encore’s net reserves are reduced by these NPI reserve volumes resulting in what is referred to in this report as post-NPI reserves. Based on our review, it is our judgment that the model employed by Encore for forecasting future NPI payments and NPI reserves is reasonably accurate for estimating the NPI impact on our estimates of reserves and future net revenues in this report.

     Williston Basin properties are located in Montana, North Dakota, and Wyoming and are grouped by producing horizon into Bakken or Non-Bakken fields. Bakken fields include Bear Creek, Charlson, Cherry,and Murphy Creek. These produce from either the Bakken or Sanish formations. Non-Bakken fields include Camp/Indian Hill, Davis Creek/Fryburg, Lodgepole, and TR. These fields produce from various horizons including Madison, Red River, Interlake, Fryburg, Lodgepole, Ratcliffe, Duperow, and Mission Canyon. Exhibits are summarized by operating category, reserves category, Bakken or Non-Bakken, and field.

Encore Acquisition Company		January 20, 2010
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     Big Horn Basin properties are located in Park County, Wyoming and Carbon County, Montana. Fields include Elk Basin, Northwest Elk Basin, South Elk Basin, and Gooseberry. 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 Gooseberry Field is a waterflood in the Big Horn Basin that has 23 producing wells in the field. The exhibits are summarized by operating category, reserves category, and field.

     Paradox Basin properties are located in San Juan County, Utah in the Four Corners region. They consist of two non-operated waterflood units, the Aneth Unit and the Ratherford Unit, that produce from the Desert Creek carbonate formation. The exhibits are summarized by producing unit.

     Powder River Basin properties are located on the northeastern flank of the basin in Powder River and Carter counties, Montana. Bell Creek Field is 15 miles long by 3.5 miles wide, covering approximately 17,000 productive acres. Encore owns a 100 percent working interest in seven producing units. Production is from the Cretaceous age Muddy Sandstone at a depth of 4,500 feet. The exhibits are summarized by operating category, reserves category, and field.

     West Texas operated fields include East Cowden Grayburg Unit, North Cowden Unit, Fuhrman-Mascho, Deep Rock, Crockett County, Sand Hills, and Brown Bassett. The East Cowden Grayburg Unit is located in Ector County, Texas and produces primarily from the Grayburg formation. It is positioned in the interior of the North Cowden Unit operated by Occidental. The Fuhrman-Mascho and Deep Rock fields are located in Andrews County, Texas and produce from the San Andres, Glorietta, Clearfork, Wolfcamp, and Pennsylvanian formations. Crockett County properties are located in the Val Verde Basin of Texas with production from several regulatory fields including Ozona, Hunt-Baggett, Davidson Ranch, and Henderson. Primary producing formations are the Strawn carbonates at 8,500 feet and the Canyon sandstones at 7,500 feet. Sand Hills Field is located in Crane County, Texas and produces from the Judkins, McElroy, McKnight, and Tubb formations. Fields recently added through a joint venture are Brown Bassett in the Val Verde Basin and Parks, Pegasus, and Wilshire in the Midland Basin. The exhibits are summarized by operating category, reserves category, and field.

     Ark-La-Tex Area properties are located primarily in four fields: (1) Elm Grove Field in Bossier Parish, Louisiana; (2) Overton Field in Smith County, Texas; (3) Stockman Field in Shelby County, Texas; and (4) Chismville Field in Logan County, Arkansas. In Elm Grove Field, Encore owns various, non-operated working interests in over 350 wells and approximately 1,800 acres. In Overton Field, Encore operates nine units which produce from 80 wells. In Stockman Field, Encore operates and produces from 15 wells. The fields located in Texas and Louisiana are typically developed on 40- to 80-acre spacing. The primary producing formations are the Hosston/Travis Peak (Louisiana/Texas), Cotton Valley, and Lower Cotton Valley Sandstones between 7,100 and 11,500 feet. In Chismville Field, Encore owns various, non-operated working interests in over 100 wells producing from the Borum, Nichols, and Turner formations. Exhibits are summarized by operating category, reserves category, and field.

Encore Acquisition Company		January 20, 2010
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     Anadarko Area properties are located in the Anadarko Basin of western Oklahoma and the Northern Shelf Basin in northern Oklahoma. Encore acquired a number of new properties in this area in 2009. Encore owns varied interests in acreage and producing wells in each of these basins. Exhibits are summarized by operating category, reserves category, and field.

     New Mexico properties are located in the Delaware Basin in Lea and Eddy Counties, New Mexico. Major fields include Cemetary, Indian Basin, Loco Hills, McCormack South, and recently added Vacuum Field. These fields produce from the Atoka, Morrow, Paddock, Silurian, and Upper Penn formations. The exhibits are summarized by operating category, reserves category, and field.

     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.

     In conducting this evaluation, we relied upon production histories, well test data, well logs, and other engineering and geological data supplied by Encore. 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 Encore. We also relied upon Encore’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 Encore or any affiliate of Encore. Our compensation for the required investigations and preparation of this report is not contingent upon the results

Encore Acquisition Company		January 20, 2010
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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.

				Very truly yours,
				MILLER AND LENTS, LTD.
				Texas Registered Engineering Firm No. F-1442
				By /s/ Leslie A. Fallon   Leslie A. Fallon, P.E.
				Vice President
				By /s/ Michael S. Young   Michael S. Young
				Senior Vice President
				By /s/ Carl D. Richard   Carl D. Richard, P. E.
				Senior Vice President

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.