Encore Energy Partners LP - FORM 10-K - EX-99.1

Attached files

file	filename
10-K - FORM 10-K - Encore Energy Partners LP	form10k.htm
EX-32.1 - EX-32.1 - Encore Energy Partners LP	exhibit32-1.htm
EX-23.2 - EX-23.2 - Encore Energy Partners LP	exhibit23-2.htm
EX-32.2 - EX-32.2 - Encore Energy Partners LP	exhibit32-2.htm
EX-23.1 - EX-23.1 - Encore Energy Partners LP	exhibit23-1.htm
EX-21.1 - EX-21.1 - Encore Energy Partners LP	exhibit21-1.htm
EX-12.1 - EX-12.1 - Encore Energy Partners LP	exhibit12-1.htm
EX-31.2 - EX-31.2 - Encore Energy Partners LP	exhibit31-2.htm
EX-31.1 - EX-31.1 - Encore Energy Partners LP	exhibit31-1.htm

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 1, 2011

Exhibit 99.1

Encore Energy Partners LP

5847 San Felipe

Suite 3000

Houston, TX 77057

Ladies and Gentlemen:

Pursuant to the request of Denbury Resources Inc. (Denbury), we have prepared an appraisal, as of December 31, 2010, of the extent and value of the proved crude oil, condensate, natural gas liquids, and natural gas reserves of certain properties owned by Encore Energy Partners LP (Encore). This report was completed on February 1, 2011. The reserves estimated in this report are located in Arkansas, Montana, North Dakota, New Mexico, Oklahoma, Texas, and Wyoming and represent 100 percent of Encore’s proved reserves. The properties appraised are listed in detail in the related DeGolyer and MacNaughton report entitled “Appraisal Report as of December 31, 2010 on Certain Properties owned by Encore Energy Partners LP SEC Case.” Denbury sold Encore to Vanguard Natural Resources, LLC on December 31, 2010, and consequently provided this report to the purchaser.

Estimates of reserves presented in this report have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (SEC). These reserves definitions are discussed in detail in the Definition of Reserves section of this report.

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2010. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Encore after deducting royalties and interests owned by others.

This report also presents values that were estimated for proved reserves using initial prices and costs provided by Denbury on behalf of Encore. Prices are related to December 31, 2010, NYMEX prices of $79.43 per barrel and $4.448 per million British thermal units (MMBtu). No escalation has been applied to prices and costs. A detailed explanation of the future price and cost assumptions is included in the Valuation of Reserves section of this report.

Values of proved reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a discount rate of 10 percent are reported.

Estimates of oil, condensate, natural gas liquids, gas reserves, and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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.

(i) 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.

(ii) 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.

(iii) 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.

(iv) 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.

(v) 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:

(i) 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

(ii) 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.

(i) 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.

(ii) 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.

(iii) 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 in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic conditions.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

The gas reserves included herein are reported as sales gas. Sales gas is defined as that gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. All gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state or area in which the reserves are located. Condensate reserves estimated herein are those to be recovered by conventional lease separation. Natural gas liquids reserves are estimated to be those attributable to the leasehold interests appraised based on historical yield information.

In the preparation of this study, as of December 31, 2010, gross production estimated to December 31, 2010, was deducted from gross ultimate recovery to arrive at the estimate of gross reserves. In some fields, this required that the production rates be estimated for up to 2 months, since production data from certain properties were available only through October 2010.

The following table presents estimates of the proved reserves, as of December 31, 2010, of the properties appraised, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

	Oil and Condensate (Mbbl)		Natural Gas Liquids (Mbbl)		Total Liquids (Mbbl)		Gas (MMcf)

Gross Proved Reserves
Developed Producing		171,778		2,147		173,925		202,188
Developed Nonproducing		26		0		26		22,904
Undeveloped		5,243		0		5,243		20,344

Total Gross Reserves		177,047		2,147		179,194		245,436

Net Proved Reserves
Developed Producing		24,600		1,210		25,810		58,866
Developed Nonproducing		5		0		5		8,133
Undeveloped		2,838		0		2,838		7,528

Total Net Reserves		27,443		1,210		28,653		74,527

Primary Economic Assumptions

Revenue values in this report were estimated using the initial prices and costs provided by Denbury. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB).

In this report, values for proved reserves were based on projections of estimated future production and revenue prepared for these properties.

The following assumptions were used for estimating future prices and costs:

Oil, Condensate, and NGL Prices

Denbury has represented that the oil and condensate prices were based on a reference price, calculated as the un-weighted average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Denbury supplied differentials by field to a NYMEX WTI reference price of $79.43 per barrel. The volume-weighted average price over the lives of the properties was $69.11 per barrel for oil and $58.72 per barrel for NGL.

Natural Gas Prices

Natural gas prices were calculated for each lease using differentials furnished by Denbury to a NYMEX price of $4.448 per MMBtu and held constant thereafter. The volume-weighted average price over the lives of the properties was $4.233 per thousand cubic feet.

Operating Expenses and Capital Costs

Current operating expenses and capital costs, based on information provided by Denbury, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

The future revenue to be derived from the production and sale of the proved reserves, as of December 31, 2010, of the properties appraised is estimated as follows:

	Proved
	Developed Producing (M$)		Developed Nonproducing (M$)		Undeveloped (M$)		Total Proved (M$)

Future Gross Revenue		2,015,700		36,129		231,183		2,283,012
Production and Ad Valorem Taxes		202,383		3,363		19,809		225,555
Operating Expenses		538,586		9,030		41,969		589,585
Capital Costs		42		4,452		47,261		51,755
Abandonment Costs		24,545		0		0		24,545
Future Net Revenue*		1,250,144		19,284		122,144		1,391,572
Present Worth at 10 Percent*		644,228		4,589		50,154		698,972

* Future income taxes have not been taken into account in the preparation of these estimates. Note: Numbers in tables may not add due to rounding.

Timing of capital expenditures and the resulting development of production were based on a development plan provided by Denbury on behalf of Encore.

In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary and Conclusions

Encore owns working and royalty interests in certain properties located in Arkansas, Montana, North Dakota, New Mexico, Oklahoma, Texas, and Wyoming. The estimated net proved reserves of the properties appraised, as of December 31, 2010, are summarized as follows, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

	Oil and Condensate (Mbbl)		Natural Gas Liquids (Mbbl)		Total Liquids (Mbbl)		Gas (MMcf)

Net Proved Reserves
Developed Producing		24,600		1,210		25,810		58,866
Developed Nonproducing		5		0		5		8,133
Undeveloped		2,838		0		2,838		7,528

Total Net Reserves		27,443		1,210		28,653		74,527

The estimated revenue and expenditures attributable to Encore’s interests in the proved reserves, as of December 31, 2010, of the properties appraised under the aforementioned assumptions concerning future prices and costs are summarized as follows:

	Proved
	Developed Producing (M$)		Developed Nonproducing (M$)		Undeveloped (M$)		Total Proved (M$)

Future Gross Revenue		2,015,700		36,129		231,183		2,283,012
Production and Ad Valorem Taxes		202,383		3,363		19,809		225,555
Operating Expenses		538,586		9,030		41,969		589,585
Capital Costs		42		4,452		47,261		51,755
Abandonment Costs		24,545		0		0		24,545
Future Net Revenue*		1,250,144		19,284		122,144		1,391,572
Present Worth at 10 Percent*		644,228		4,589		50,154		698,972

* Future income taxes have not been taken into account in the preparation of these estimates. Note: Numbers in tables may not add due to rounding.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2010, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Encore. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Encore. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.

All gas quantities in this report are expressed at a temperature base of 60 °F and at the legal pressure base of the state or area in which the reserves are located.

Very truly yours,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas 75244, U.S.A., hereby certify:

1.	That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare our letter report to Encore Energy Partners LP dated February 1, 2011, and that I, as Senior Vice President, was responsible for the preparation of this report.

That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have in excess of 36 years of experience in oil and gas reservoir studies and evaluations.

/s/ Paul J. Szatkowski, P.E.

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton

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